In-situ detection and analysis of methane in coal bed methane formations with spectrometers

ABSTRACT

The invention subject of this disclosure teaches a method of determining a production factor for a carbonaceous material reservoir, the method comprising: providing a well in a carbonaceous material reservoir; providing unsampled fluid at a depth in the well; placing a sensor adjacent to the unsampled fluid and performing a measurement on the unsampled fluid; using data from the measurement to determine a partial pressure of a solution gas in the carbonaceous material reservoir; and determining a production factor for the carbonaceous material reservoir from the partial pressure of the solution gas.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Divisional application of application Ser. No.13/545,334 which is a continuation in part of reissue application Ser.No. 11/332,388 filed Jan. 13, 2006 (now RE44728 issued Jan. 28, 2014) ofU.S. Pat. No. 6,678,050 which claims priority to International PatentApplication No. PCT/US01/11563, filed Apr. 11, 2001, designating theUnited States of America, and published as WO 01/77628, the entiredisclosure of which is incorporated herein by reference. U.S. Pat. No.6,678,050 claims priority based on Provisional Application Nos.60/196,620, 60/196,182, 60/196,523 and 60/196,000 filed Apr. 11, 2000.This application is also a continuation in part of application Ser. No.11/855,945 filed Sep. 14, 2007 and claiming priority to U.S. ProvisionalPatent Application No. 60/661,152 filed Mar. 14, 2005. The entiredisclosure of which is hereby incorporated by reference. Thisapplication also is a continuation in part of provisional applicationNo. 61/602,939 filed Feb. 24, 2012 entitled “In-situ Detection andAnalysis of Methane in Coal Bed Methane Formations with Spectrometers”which is incorporated by reference herein.

TECHNICAL FIELD

This invention relates to in-situ methods of measuring or analyzingdissolved, free, or embedded substances with a spectrometer and anapparatus to carry out the method. In particular this invention relatesto a method and apparatus of analyzing substances down a well. Moreparticularly, this invention relates to a method and apparatus todetect, analyze and measure methane or related substances in subsurfacecoal bed formations using a portable optical spectrometer to therebypredict a potential methane production of the well.

This invention also relates to a method and system of determining gascontent, dewatering time, critical desorption pressure, and/or otherreservoir and operational variables, referred to as production factors,for coalbed natural gas wells, other carbonaceous material reservoirwells including carbonaceous shale, shales, tight sands, and muddy sandsor other methane reservoirs wherein the methane is at least partiallydissolved in water within the reservoir. In particular, this inventionrelates to a method and system for measuring a partial pressure ofmethane or a predictor substance for a coalbed natural gas reservoir anddetermining production factors therefrom.

Apparatus and Method of Combining Zonal Isolation and In SituSpectroscopic Analysis of Reservoir Fluids for Coal Seams

This invention relates methods and apparatus that enable activeisolation and analysis of coal seam reservoirs. Prior art has disclosedmethods of testing coal seam reservoir fluids and thereby measuringproduction factors of interest including critical desorption pressure,coal gas content, and the like. However, testing multiple coal seamssituated at various depths in the same location is difficult due tocommingling of the fluids from the coal seam reservoirs that typicallyenter a well that intersects and is completed in more than one seam. Asa result, fluids in such wellbores may originate from more than one coalseam, or only one coal seam, depending on relative coal seam pressures,and analysis of such fluids cannot readily be attributed to a particularreservoir.

This invention allows ready attribution of fluid properties to thecorrect coal seam by actively isolating coal seams in a wellbore,drawing out fluid from each coal seam, analyzing such fluid, and therebyanalyzing the production factors of interest in that particular coalseam.

The invention also relates the apparatus that can be used in thismethod. This apparatus includes isolating the coal seams by usingexisting casing, by setting bridge plugs and retrievable bridge plugs,by using pack-off technologies, and/or by using active pumping to favorproduction of water from a particular seam.

The invention also describes use of a down hole spectroscopic analyzerand a surface spectroscopic analyzer that is coupled to a down holesensor analysis chamber using optical fibers with the coal seamisolation apparatus and the use of pressure gauges situated at twodifferent depths within or above the zonal isolation apparatus tomeasure properties of the produced water

The invention also describes an apparatus comprising two pressuresensors located at different heights above a valve assembly. Alsodescribed is a method comprising using two pressure gauges located attwo separate vertical heights within the well bore with the ability tocompute the partial pressure of methane dissolved in the produced fluid.The method measures the bubble point of the dissolved methane. Themethod plots the gauge pressure readings on the y axis and hydrostatichead of the produced fluid in the work string on the x axis.

The disclosure further provides a new reservoir evaluation technologyutilizing spectroscopic analysis and other fluid measurements to beconducted at the well surface rather than downhole in the well.

The disclosure further provides for testing and analysis with placementof the spectrometer and detector at the well surface and a housingcomprising a radiation source and window positioned downhole in thewell. The radiation source is connected to the guide wire furnishingelectrical power, and with characteristic radiation for the sampletransmitted by a separate optical pathway, comprising an optical fiberto the spectrometer. The detector may be connected to the spectrometerthrough a separate fiber optic cable.

Further disclosed in this specification are means for verifying that thefluid being analysed is representative of reservoir conditions and withbubble point of dissolved methane being obtained by measurement ofpressure of two disparate locations in the fluid column of the well.

BACKGROUND AND SUMMARY OF THE INVENTION

Coal bed methane is methane that is found in coal seams. Methane is asignificant by-product of coalification, the process by which organicmatter becomes coal. Such methane may remain in the coal seam or it maymove out of the coal seam. If it remains in the coal seam, the methaneis typically immobilized on the coal face or in the coal pores and cleatsystem. Often the coal seams are at or near underground water oraquifers, and coal bed methane production is reliant on manipulation ofunderground water tables and levels. The underground water oftensaturates the coal seam where methane is found, and the undergroundwater is often saturated with methane. The methane may be found inaquifers in and around coal seams, whether as a free gas or in thewater, adsorbed to the coal or embedded in the coal itself.

Methane is a primary constituent of natural gas. Recovery of coal bedmethane can be an economic method for production of natural gas. Suchrecovery is now pursued in geologic basins around the world. However,every coal seam that produces coal bed methane has a unique set ofreservoir characteristics that determine its economic and technicalviability. And those characteristics typically exhibit considerablestratigraphic and lateral variability.

In coal seams, methane is predominantly stored as an immobile,molecularly adsorbed phase within micropores of the bulk coal material.The amount of methane stored in the coal is typically termed the gascontent.

Methods of coal bed methane recovery vary from basin to basin andoperator to operator. However, a typical recovery strategy is a well isdrilled to the coal seam, usually a few hundred to several thousand feetbelow the surface; casing is set to the seam and cemented in place inorder to isolate the water of the coal from that of surrounding strata;the coal is drilled and cleaned; a water pump and gas separation deviceis installed; and water is removed from the coal seam at a rateappropriate to reduce formation pressure, induce desorption of methanefrom the coal, and enable production of methane from the well.

Assessment of the economic and technical viability of drilling a coalbed methane well in a particular location in a particular coal seamrequires evaluation of a number of reservoir characteristics. Thosecharacteristics include the gas content and storage capability of thecoal; the percent gas saturation of the coal; density, permeability, andrecovery factor. the gas desorption rate and coal permeabilityanisotropy; and gas recovery factor.

While industry has developed methods to enhance production fromformations that exhibit poor physical characteristics such aspermeability and density, practical methods to increase the gas contentof a coal seam remain under development. Thus, identifying coal seamsthat contain economic amounts of methane is a critical task for theindustry. The primary issue developing a method in identifying such coalseams involves developing a method and apparatus to quickly andaccurately analyze coal seams for gas content.

Currently accepted methods of measuring gas content involve extracting asample of the coal from the seam and measuring the amount of gas thatsubsequently desorbs, either by volume or with a methane gas sensor.However, collection of the coal sample usually changes its gas contentto a significant extent before gas desorption is monitored. Thisdegradation of sample integrity leads to degradation of the datacollected. That degradation of data creates significant doubt in theresults of those common methods. As well, because these methods hinge onwaiting for the methane to desorb from the coal, they require inordinateamounts of time and expense before the data is available.

Downhole sensing of chemicals using optical spectroscopy is known foroil wells. For example, Smits et. al., “In-Situ Optical Fluid Analysisas an Aid to Wireline Formation Sampling”, 1993 SPE 26496, developed anultraviolet/visible spectrometer that could be placed in a drill string.That spectrometer was incorporated in a formation fluid sampling toolwhereby formation fluids could be flowed through the device and analyzedby the spectrometer. That spectrometer was largely insensitive tomolecular structure of the samples, although it was capable of measuringcolor of the liquids and a few vibrational bond resonances. The deviceonly differentiates between the O—H bond in water and the C—H bond inhydrocarbons and correlates the color of the analyte to predict thecomposition of the analyte. The composition obtained by the device isthe phase constituents of the water, gas and hydrocarbons. Bycorrelating observation of gas or not gas with observation of water,hydrocarbon, and/or crude oil, the instrument can distinguish betweenseparate phases, mixed phases, vertical size of phases, etc. Bycorrelating the gas, hydrocarbon, and crude oil indicators, theinstrument can presumably indicate if a hydrocarbon phase is gaseous,liquid, crude, or light hydrocarbons. A coal bed methane well with coalto methane and, possibly, bacterial material, provides an environmenttoo complex for such a device to differentiate methane and the othersubstances of interest. The device is not capable of resolving signalsfrom different hydrocarbons to a useful extent, and the device is notcapable of accurate measurements needed for coal bed methane wells.Furthermore, the requirements that the sample be fluid, that analysisoccur via optical transmission through the sample, and that the samplebe examined internal to the device precludes its use for applicationssuch as accurately measuring gas content of coal seams.

In other apparatuses known in U.S. Pat. No. 4,802,761 (Bowen et. al.)and U.S. Pat. No. 4,892,383 (Klainer, et. al.), a fiber optic probe ispositioned to transmit radiation to a chemically filtered cell volume.Fluid samples from the surrounding environment are drawn into the cellthrough a membrane or other filter. The fiber-optic probe then providesan optical pathway via which optical analysis of the sample volume canbe affected. In the method from Bowen et. al., a Raman spectrometer atthe well head is used to chemically analyze the sample via the fiberoptic probe. The method allows purification of the downhole fluidsamples via of the wellhead is the fiber optic downhole fluid samplesusing chromatographic filters and subsequent analysis of the fluid andits solutes using Raman spectroscopy. However, the stated requirementthat the Raman spectrometer be remote from the samples of interest andthat it employ fiber-optic transmission devices for excitation andcollection ensures that the sensitivity of the device is limited. Thedevice further does not consider the conditions present in subsurfacewells when analyzing the samples. Furthermore, as in the Smits et. al.case, the requirements in Bowen et. al. and Klainer et. al. that thesample be fluid and that the sample be examined internal to the devicesignificantly decrease the utility of the device for applications suchas measuring gas content of coal seams.

Methods of sample preparation and handling for well tools have beendescribed, as well. In U.S. Pat. No. 5,293,931 (Nichols et. al.), anapparatus is disclosed for isolating multiple zones of coal bedformations (coal seams) in a well bore. The isolation allows isolatedpressure measurements through the well bore or wellhead collection ofsamples of fluids from various positions in the wellbore. However, suchwellhead sample collection degrades sample integrity and does notprovide a practical method or apparatus for assessment of gas content incoal seams. The apparatus shown significantly affects any samplecollected and is basically a collection device set down a well.

An object of the invention is to provide a method and system—toaccurately measure substances in wells using optical analysis.

Another object of the invention is to provide a method and measuringsystem capable of measuring methane in a coal bed methane well.

Another object of the invention is to provide a method and measuringsystem which utilizes a spectrometer to analyze methane and othersubstances with emitted, reflected or scattered radiation from thesubstances and thereby allow a measurement of a side surface of thewell.

Another object of the invention is to provide a method and measuringsystem to accurately measure a concentration of methane in a coal bedmethane well and calculate a concentration versus depth for a singlewell and calculate concentrations versus depth for other wells tothereby predict a potential production of a coal bed methane field.

The objects are achieved by a measuring system for introduction into awell with a housing traversable up and down the well, a guide extendingdown the well from a fixed location and being operatively connected tothe housing, a spectrometer being located inside the housing andincluding a radiation source, a sample interface to transmit a radiationfrom the radiation source to a sample, and a detector to detect acharacteristic radiation emitted, reflected or scattered from the sampleand to output a signal, and a signal processor to process the signalfrom the detector and calculate a concentration of a substance in thesample.

Another aspect of the invention is a measuring system. A portion of thesystem is introduced into a well with a housing traversable up and downthe well, a guide extending down the well from a fixed location andbeing operatively connected to the housing. The housing incorporates aradiation source, which is electrically powered, either by a batterylocated in the probe or via the guide wire, a sample interface totransmit a radiation from the radiation source to a sample, and anoptical pathway for transmission of a characteristic radiation emitted,reflected or scattered from a sample to a detector situated in aspectrometer located at ground surface. The detector is opticallyconnected to the housing. The surface spectrometer also includes asignal processor to process the signal output from the detector with themeasurement system including means to calculate a concentration of asubstance in the sample.

Another aspect of the invention is a measuring system for in-situmeasurements down a well by a surface spectrometer. The spectrometerincludes a radiation source and a detector. A probe is providedoptically connected to the spectrometer and including an optical pathwayfor transmission of a radiation from the radiation source and at least asecond optical pathway for transmission of a characteristic radiationfrom a sample to the detector. A positioner is provided to position theprobe near a side surface of the borehole and to optically couple theoptical pathways to the side surface of the borehole, wherein the probeis traversable up and down the well by way of a guide operativelyconnected to the probe and to a fixed location at the wellhead.

Another aspect of the invention is a measuring system for in-situmeasurements down a well by a surface spectrometer, which includes adetector. A probe is provided that is optically connected to thespectrometer. The probe houses a radiation source, which is electricalpowered, either by a battery located in the probe or via a guide wire,and an optical pathway for transmission of a characteristic radiationfrom a sample to the detector. A positioner is provided to position theprobe near a side surface of the borehole and to optically couple theoptical pathways to the side surface of the borehole, wherein the probeis traversable up and down the well by way of a guide operativelyconnected to the probe and to a fixed location at the wellhead

Another aspect of the invention is a method of measuring methane in atleast one coal bed methane well. An instrument package is provided in ahousing, and the housing is lowered a distance down the well. Aradiation source is positioned to irradiate a sample, and a detector ispositioned to detect the characteristic radiation from the interactionbetween the sample and the incident radiation from the radiation source.The sample is irradiated to produce the characteristic radiation. Theconcentration of methane in the sample is measured by detecting thecharacteristic radiation with the detector. The detector transmits asignal representative of the concentration of methane to a signalprocessor, and the signal processor processes the signal to calculatethe concentration of methane in the sample.

In another aspect of the invention, a method of measuring a side surfaceof a borehole using optical spectrometers is provided. An opticalspectrometer with a radiation source and a detector is provided. Theside surface of the borehole is optically connected to the radiationsource and the detector. The radiation source irradiates the sidesurface of the borehole, and the emitted, reflected or scatteredcharacteristic radiation from the side surface of the borehole iscollected. The collected characteristic radiation is transmitted to thedetector to output or produce a signal. The signal is transmitted to asignal processor and the concentration of a substance on the sidesurface of the borehole is calculated.

The side surface is usually a solid material such as coal, sandstone,clay or other deposit. The side surface has been affected by the drillbit. The side surface may also have a film of drilling “mud” or someother contaminant (introduced or naturally found) that has beendistributed by the drill bit. The measurement system analyzes thesurface of that material, or the material is penetrated to analyze itsinterior. The surface may be treated (i.e. by washing it with water)before being analyzed. The material of interest is characterized alongwith any other materials adsorbed or absorbed to the material. Thesecould include gases, liquids, or solids. Preferably, the methaneadsorbed to the coal surface and in its pores is identified. The amountof methane on the surface and in the pores is measured.

The samples of interest may be a face of the coal seam, the coal itself,a bacterium or bacterial community which may indicate methane, the waterin the well, methane entrained in the coal or water, methane dissolvedin the water; or free gas. A free gas may be examined in-situ byproviding a pressure change to the water or to the coal and collectingthe resultant gas by way of a head-space. The sample or substance ofinterest may be physically, biologically or chemically treated in-situbefore measuring to enhance detection or measurement.

The radiation source is of particular concern and is selected dependingon the well environment, the substance to be measured and the backgroundof the sample. Coal shows inordinate fluorescence, and often bacteriaand other organic material are present near the coal seams. Thesesubstances tend to produce fluorescence which interferes withmeasurements of other substances. Unless the fluorescence is measured,the radiation source and wavelength are selected to minimize theseeffects. Coal tends to fluoresce between 600 nm and 900 nm with asignificant drop in fluorescence under 600 nm. A radiation source whichtakes into account these ranges is preferred for measuring the methane,especially the methane adsorbed to or embedded in the coal. Thus, themethane signature relative to the other components is maximized. In someinstances a signature of the fluorescence is maximized to characterizethe methane indirectly.

The measurements lead to establishing a concentration of methane in thecoal bed formation and to the potential production or capacity of thecoal bed. The methane is analyzed by obtaining through spectrometers aseries of spectra representative of scattered, emitted or reflectedradiation from methane in the well. The captured spectra are used todetermine the concentration at varying depths of methane present in thecoal bed formation. The spectra are manipulated and analyzed to producethe concentrations of methane represented in the well. The use offilters which are designed to eliminate or reduce radiation from sourcespresent in the well is needed to accurately determine the methaneconcentration or other parameters of the coal bed methane well. Otherparameters may include a predictor element or compound that is naturalor introduced to the coal bed or well. The filters are chosen dependingon the chemical which is of interest. Raman spectrometers are used inmost testing, however, near infrared lasers and detectors may beemployed to avoid the difficulties associated with fluorescence frommaterial or substances in the water or well. The measuring system inthis invention is based on high sensitivity. One factor that is used tomaintain high sensitivity of the system is the reduction or eliminationof moving parts throughout the measuring system.

Traditionally, coal bed methane production factors have been determinedby a variety of methods. One method involves retrieval of a core sampleof the coal, transportation of the core sample to a laboratory setting,and quantification of the amount of methane contained within the samplecoal via gas desorption. This quantity is then analyzed to determine thecoal gas content and compared to an adsorption isotherm of the same or asimilar coal in order to determine the critical desorption pressure ofthe coalbed reservoir. This process is expensive, time consuming, anderror-prone.

Those skilled in the art will recognize that reference to a partialpressure of gas dissolved in a fluid is related to the amount of thatgas that is dissolved in that fluid and that would be in equilibriumwith a vapor phase in contact with that fluid. Use of the term “partialpressure of gas in fluid” is meant to encompass, but not be limited to,related terms such as concentration, effective density, quantity,potential volume, potential pressure, and amount.

An aspect of certain preferred embodiments of the invention providesthat a production factor such as gas content, dewatering time, criticaldesorption pressure, and/or other reservoir and operational variablescan be determined via measurement or determination of methane partialpressure or another substance or substances indicative of the methanepartial pressure.

The critical desorption pressure of the coal bed methane reservoir orcoal seam is equal to the methane partial pressure of the reservoir orcoal seam. By determining the effective methane partial pressure of thecoal, reservoir fluid or well fluid the critical desorption pressure maybe determined. If the system is in physical and chemical equilibrium thepartial pressures of methane for the reservoir, coal, reservoir fluidand well fluid are all equal. However, in practice this is not alwaysthe case as many variables may affect the partial pressures and theirinterrelation to one another. In such cases other measurements ordeterminations may be used to correlate the partial pressures.

Other production factors may be determined utilizing the partialpressure of methane via correlation, modeling, calculation, and othersensor data.

The measurement of the partial pressure of methane can be accomplishedvia measurement of a dissolved methane concentration. Preferably, themeasurement of the concentration is done at a depth of the coal seam andas near to the coal seam as possible so that other variables and effectsare lessened. This concentration is then correlated to a partialpressure of methane of the well fluid, reservoir fluid or coalreservoir. The partial pressure of methane within the coal reservoir isthen used to determine the critical desorption pressure along with a gascontent of the coal reservoir, dewatering time and other reservoir andoperational variables.

The measurement or determination of the partial pressure may also beaccomplished in other ways such as by direct measurement of the partialpressure via instrumentation or another variable which correlates to thepartial pressure of methane.

In a preferred embodiment, the methane concentration or anothersubstance's concentration dissolved in a coal seam reservoir fluid ismeasured at a depth in the well at or near the coal seam of interest.This concentration is then correlated to a partial pressure of methanein the fluid. This partial pressure of methane in the fluid is thencorrelated to the partial pressure of methane in the reservoir whichequates to the critical desorption pressure.

In certain preferred embodiments of the invention a method fordetermining a production factor or gas content of a coal seam isachieved by direct measurement of methane concentration of the wellborefluid. This measurement in combination with a known or determinedsolubility property for methane in water allows the calculation of thepartial pressure of methane in the wellbore fluid.

If the fluid in the wellbore is in equilibrium with the reservoir fluid,which in turn is in equilibrium with the coal seam itself, thehydrologic and physical connection between these fluids and the coalallows that the measurement of one of these partial pressures can becorrelated into a measurement of the other two. The partial pressure ofthe fluids is controlled by the amount of methane present in the coalseam. More simply stated; when more methane is present in a particularcoal seam, the partial pressure of methane in the fluids is higher.

The methane partial pressure of the coal seam is the critical desorptionpressure, which is the saturation point of the coal seam at thatpressure. Dewatering of the well acts to lower the total fluid pressureto a value at or below the critical desorption pressure, which causesdevolution of methane out of the coal seam as free gas.

Having determined the critical desorption pressure, by further utilizingan isotherm of the interested coal seam calculations can be made todetermine the gas content of the coal seam and estimate the totalmethane reserves. As well, the critical desorption pressure can becompared to the rate of decrease of the total reservoir pressure duringdewatering, the rate of flow of water from the coal seam, and otherreservoir and operational variables, in order to predict dewateringtime, permeability, and other production factors.

The concentration of the methane or other substance or the partialpressure of methane in the reservoir fluid may be measured by opticalspectrometers, membrane-covered semiconductor sensors, massspectrometers or the like.

The concentration which is measured may be directly correlated to apartial pressure of methane in the reservoir or any intermediatequantity that is relatable to the amount of methane in the fluid orparts of the fluid. Each coal seam has unique properties which mayaffect the correlations. By using an intermediate correlation theseproperties may be used to enhance the accuracy and precision of thepartial pressure determination of the methane in the reservoir.

The production factors which may be determined are gas partial pressure,percent saturation of gas in coal, gas content, bookable reserves,permeability, porosity, relative permeability, critical desorptionpressure, dewatering time, solution gas, stage of production, cone ofdepression, cross-seam water and gas flow, water salinity,identification of contributing seams and formations, density, coalfriability, cleat and fracture structure including size, distributionand orientation, dewatering area and volume, degassing area and volume,gas concentration, reservoir pressure, gas recovery factor,gas-in-place, water and gas production rates and timetables, welllifetime, optimum well spacing, optimum production procedures includingchoice of which seams in multi-zone wells and which wells in a podshould be produced first, second, etc., optimum completion proceduresincluding choice of which seams and wells to complete first, second,etc., which to abandon or sell, and how to complete and produce thedesired wells, effectiveness of prior completion and productionactivities, indication of regions and seams of favorable productionpotential, and other production factors which will be apparent to thoseskilled in the art.

Another aspect of the invention is an apparatus and/or system whichmeasures the partial pressure of methane or another substance indicativeof the methane or measures a precursor variable such as theconcentration of methane to allow or produce a determination of themethane partial pressure of the reservoir. The system may include apressure transducer. The pressure transducer can measure the totalpressure of the fluid at the measurement point. The transducer can alsomeasure a gas pressure down a wellbore when the methane is evolved fromthe water.

Preferably, the concentration or partial pressure is measured by Ramanspectroscopy. This may be accomplished by lowering a probe or housingwithin the well which contains the spectrometer or parts thereof or byguiding a radiation from a radiation source into the well and onto thefluid at or near the coal seam from the spectrometer located outside ofthe well. Characteristic radiation may also be guided from the fluid tothe spectrometer located outside the well. Most preferably, themeasurement is conducted on the fluid without first sampling the fluid.During sampling, the fluid is necessarily transported and disturbed. Bymeasuring the fluid outside of an instrument package and in-situ theresultant concentration or partial pressure is more accurate.

This invention describes a method of combining physical isolation ofsubsurface geological formations with spectroscopic analysis of fluidsand fluid pressure measurements in order to quickly and accuratelymeasure key properties of multiple formations in a single wellbore. Themethod enables, in one embodiment, rapid assessment of each formation asa possible natural gas (methane) production target.

Alone, zonal isolation is well known and widely practiced, but is of useonly in limited circumstances, such as when measuring fluid movementrates and wellbore pressure changes in order to evaluate permeabilityand skin damage. Alone, in situ downhole and surface spectroscopic fluidanalysis has been perfected and commercially deployed, but it ischallenged in some cases by the movement of fluid downhole betweenformations in the wellbore, complicating analysis and interpretation ofresults when more than one formation is open to a wellbore.

By combining zonal isolation and downhole spectroscopic fluid analysisin a specific manner, this invention provides the unexpected benefit ofenabling in-situ measurement of fluid properties for multiple zones in asingle wellbore without requiring an intervening cemented casing,allowing fast, accurate evaluation of multiple possible production zonesin a single well. The method further allows differentiation of fluidsfrom each of these zones, and thereby differentiation of the propertiesof the formations. The method allows the possibility of determination ofcross communication between formations at locations away from thewellbore.

A further unexpected benefit involves the resulting ability to movefluids into and out of each formation independently, thereby providingthe ability to obtain far acting (i.e. unperturbed from their naturalstate) reservoir fluids for analysis even in cases where fluid invasioninto the formation has occurred.

A further unexpected benefit involves the resulting ability to combine avariety of complementary fluid physical and geochemical measurements,such as carbon isotope enrichment, fluid conductivity, fluidtransmissivity, and methane concentration measurements, together withdetermination of formation bulk permeability, in a single operationaltest. The method is also suitable for use in a production test modewhereby the fluids are isolated downhole and then delivered to thesurface for analysis.

Other objects, advantages and novel features of the present inventionwill become apparent from the following detailed description of theinvention when considered in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a side plan view of an embodiment of the invention and acoal bed methane well with the spectrometer located at the wellhead andtransmission of optical radiation using fibers to a downhole probe;

FIG. 2 shows a side plan view of another embodiment of the invention anda coal bed methane well with the spectrometer located in a housinglowered down the well;

FIG. 3 shows a sectional view of an embodiment of the housing with aflow passage for liquid or gas analysis;

FIG. 4 shows a sectional view of an embodiment of the housing with anon-contacting sample interface;

FIG. 5 shows a sectional view of an embodiment of the housing with ahead-space for gas analysis;

FIG. 6 shows a sectional view of an embodiment of the housing with anoff axis sample interface pressing to a side of the borehole;

FIG. 7 shows a sectional view of an embodiment of the probe with a fiberoptics;

FIG. 8 shows a sectional view of an embodiment of the probe with asample interface pressed against the side of the borehole;

FIG. 9 shows a sectional view of an embodiment of the probe with thespectrometer located downhole and a sample interface as a fiber-opticbundle pressed against the side of the borehole;

FIG. 10 shows a sectional view of an embodiment of the probe with a flowpassage and fiber-optic tip as the sample interface; and

FIG. 11 shows a sectional view of an embodiment of the probe with afiber-optic optical pathway.

FIG. 12 shows a side plan view of another embodiment of the inventionand a coal bed methane well with the spectrometer located at surface andthe radiation source in a housing lowered down the well;

FIG. 13 shows a completed coalbed methane wellbore,

FIG. 14 shows a diagram of an isotherm calculation based on a gascontent,

FIG. 15 shows a diagram of the coal bed-reservoir fluid system inequilibrium,

FIG. 16 shows a graph of a dewatering measurement,

FIG. 17 shows a process diagram of the measurement system,

FIG. 18 shows a graph of a spectral signature for methane at threedifferent concentrations,

FIG. 19 shows a graph of a calibration between signal (i.e. instrumentresponse) to methane concentration,

FIG. 20 shows a graph of a relationship between dissolved methaneconcentration and partial pressure of methane in a reservoir fluid,

FIG. 21 shows a graphical representation of the relationship betweenmethane partial pressure and coal gas content,

FIG. 22 shows a representation of a wellbore with concentrationsplotted,

FIG. 23 shows a graph of a measurement when pumping is changed,

FIG. 24 shows a diagram of an isotherm calculation based on a criticalpressure,

FIG. 25 shows a graph of multiple tests for various wells as plotted onan isotherm,

FIG. 26 shows a flow chart of measurements for a spectrometer,

FIG. 27 shows an averaged coal isotherm, and

FIG. 28 shows a diagram of a measuring device.

FIG. 29 illustrating a cross sectional view of a test equipmentconfiguration with isolation packers in relation to a coal seam.

FIG. 30 illustrates a cross sectional view of multiple tubes forconveying fluid and fiber optic or power lines.

FIG. 31 illustrates another cross sectional view of fluid conveyingtubes configured on the outer surface of a well bore casing.

FIG. 32 illustrates a view of a vertical configuration of analyticequipment and zone isolating packers.

FIG. 33 illustrates a plot of difference in measurements by two pressuregauges at different vertical heights in a fluid column versus thehydrostatic pressure at bottom of the fluid column.

The accompanying drawings, which are incorporated in and constitute apart of the specification, illustrate preferred embodiments of theinvention. These drawings, together with the general description of theinvention given above and the detailed description of the preferredembodiments given below, serve to explain the principles of theinvention.

DETAILED DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a coal bed methane well 1 with a borehole 3 extending froma well head to a coal seam 10 with an aquifer fed water level 9. Thespectrometer 4 is located at or near the wellhead and includes aradiation source 5 for producing a radiation to transmit down theborehole 3 to a sample interface 17. The radiation from the radiationsource is transmitted by way of at least one optical pathway 7. Thesample, in this case beings water, interacts with the radiationtransmitted from the radiation source 5, and a characteristic radiationfor the sample is produced by the interaction. The characteristicradiation is then transmitted by an optical pathway 7 to a detector 6located in the spectrometer 4 at the surface. A suitable optical pathway7 for transmission is optical fiber 8. Similar elements are representedby the same reference numeral in the drawings.

The optical fiber 8 extends down the borehole 3 to the housing 12 andfeeds into the housing through a high-pressure feed-through jacket 18.The jacket 18 allows the fiber 8 to enter the housing 12 withoutsubjecting the housing to the conditions down the well, such as highpressure, particles and the water. The housing protects any filter 14 orother instrumentation enclosed by the housing. The fiber 8 may extendout of the housing through another jacket 18 to optically couple thesample or substance of interest. A tip 15 of the fiber 8 supplies theradiation from the radiation source 5 and collects the characteristicradiation.

The optical fiber 8 may be a bundle of fibers where the center fibertransmits the radiation from the radiation source 5 and the other fiberstransmit the characteristic radiation. A single collection fiber for thecharacteristic radiation may also be used. The fiber 8 may also includea lens. The fibers use a polished tip or fused tip.

The sample interface includes an inlet 16 and an outlet 17 for the waterin the well. The water flows into the inlet when the housing ispositioned down the well at a depth and flows around the tip 15 of thefiber to thereby interact with the radiation from the radiation source5.

In another embodiment shown in FIG. 12, the spectrometer 4 is located ator near the wellhead, with the radiation source 5 located in a housing12, thus reducing the effects of the long distance transmission of theradiation. The spectrometer 4 is lowered down the borehole 3 by a guidewire 21 to a depth, and the depth is controlled by a guide controller 20at the surface 2. The radiation from the radiation source is transmittedby way of at least one optical pathway 7. The sample, in this case beingwater, interacts with the radiation transmitted from the radiationsource 5, and a characteristic radiation for the sample is produced bythe interaction. The characteristic radiation is then transmitted by anoptical pathway 7 to a detector 6 located in the spectrometer 4 at thesurface. A suitable optical pathway 7 for transmission is optical fiber8. The radiation source is electrically powered by either a battery 46or via the guide wire 21.

In a preferred embodiment shown in FIG. 2, the spectrometer 4 is locateddown the well 1 in a housing 12, thus reducing the effects of the longdistance transmission of the radiation. The spectrometer 4 is lowereddown the borehole 3 by a guide wire 21 to a depth, and the depth iscontrolled by a guide controller 20 at the surface 2.

This embodiment shows the radiation source 5 providing radiation by anoptical pathway 7 which is not a fiber. The radiation is directed to abeam splitter 23 and through a window 24 to interact with the sample orsubstance of interest. The emitted, reflected or scattered radiation isthen transmitted through the window 24 into the interior and through thebeam splitter 23 to the detector 6.

In this embodiment, no moving parts are present in the housing 12. Thisallows for increased sensitivity and accuracy.

The guide wire 21 may be a wireline, comprising an insulated electricalconductor inside a braided inner and outer armour, or a slickline, whichfeatures a solid smooth non-braided metal construction, coiled tubing,drill stem or other type of guide. The guide wire is provided forpositioning the housing down the well and may also transmit a signal toa data recorder or other processor at the surface. If the signal is nottransmitted by the guide wire, a signal or data storage device is neededin the housing. The guide wire may also furnish electrical power to theinstrumentation located in the housing, or a battery may be located inthe housing.

FIGS. 3-6 show embodiments of the housing 12 with the spectrometer 4enclosed therein, when used with a guide wire 21. FIG. 3 shows a flowpassage for the sample interface where the radiation source 5 providesan incident radiation through a window 24 to interact with water. Thecharacteristic radiation is transmitted through another window 24 to thedetector 6. The characteristic radiation passes through filters 4 beforethe detector 6. The housing 12 itself may be streamlined 26 to providefor smooth passage of the housing down the well.

FIG. 4 shows a housing 12 designed for a non-contacting sample interfaceat the tip of the housing. Here the radiation source 5 producesradiation which is transmitted by an optical pathway 7 to a reflector orgrating 27 to direct the radiation through a window 24 at the tip of thehousing. The radiation interacts with the sample or substance ofinterest a distance away from the window 24. The characteristicradiation is then transmitted through the window 24 and to a reflectoror grating 27 to direct the characteristic radiation to the detector 6.

FIG. 5 shows a confocal arrangement for the housing 12. The radiationsource 5 provides radiation directed to a beam splitter 23 whichreflects the radiation to a lens 30 and through a window 24 into ahead-space 31. The characteristic radiation travels to the beam splitter23 and to another filter 14 and other lens 30 to the detector 6.

The sample interface includes the head-space 31 which entraps gasproduced by a depressurization of water in the flow passage. A plunger33 or other device is used to depressurize the water. The head-space 31collects the gas for measurement and analysis. Gates 32 are providedwhich allow the water to flow into the housing and then isolate thewater from the well to allow for depressurization.

FIG. 6 shows an off-axis spectrometer 4 configuration. The radiationsource 5 is off-axis from the well and face of the borehole 3. Theradiation source 5 provides a radiation down an optical pathway 7through a lens 30 and window 24 onto a sample or substance of interest.The characteristic radiation travels through the window 24, another lens30 and a filter. 14 to the detector 6. The housing 12 has an adjustabledevice to press the housing to the side surface of the borehole. Anextendable leg 36 is provided that by a controller 37 moves out from thehousing 12 and contacts the side surface of the borehole opposite thewindow 24 and thereby moves the housing 12 towards the opposite side ofthe borehole. The confocal, off axis and non-contacting opticsarrangements may be interchanged.

FIGS. 7-11 show embodiments of the housings 12 where fiber optics 8 areemployed as at least a portion of the optical pathway 7. FIG. 7 shows ahousing 12 as a probe where the spectrometer is not located in thehousing. An optical fiber 8 supports the probe and positions the probealong the wellbore. A high-pressure feed-through jacket 18 is used toallow the fiber 8 to enter the housing 12 where filters 14 or otherdispersive elements are arranged. The fiber 8 exits the housing and thesample interface is a tip 15 of the fiber 8.

FIG. 8 shows the use of fiber 8 with an adjustable device for pressingthe sample interface against the side surface 11 of the wellbore. A bag40 is expanded by a controller 41 against the opposite side surface ofthe borehole to thereby press the tip 15 of the fiber 8 against or intothe side surface of the borehole.

FIG. 9 shows the use of fibers where the spectrometer 4 is located inthe housing 12. The radiation source 5 provides radiation to the fiber 8which transmits it to the sample by way of a jacket 18. A return fiber 8is adjacent or abutting the first. fiber at the sample interface andextends through the jacket 18 to the detector 6. The housing 12 also hasan extendable leg 36 and controller 37 for pressing the housing 12 tothe side surface 11.

FIG. 10 shows a fiber optic extending down the well and entering ahousing 12 with a flow passage. A filter 14 or other dispersive elementsare enclosed in the housing 12 and protected from the well environment.The fiber-optic tip 15 protrudes through a jacket 18 into the flowpassage. The flow passage includes an inlet 16 with a filter 45 tofilter particulates and other entrained material in the water and anoutlet 17.

FIG. 11 shows a fiber 8 optical pathway which enters the housing 12 andprovides the transmitted radiation to a filter 14 or other dispersiveelement, lens 30 and window 24.

Optical spectrometers include, but are not limited to, Transform Ramanspectrometers, of utility for this method Raman spectrometers, Fourierinfrared (IR) spectrometers, Fourier Transform infrared spectrometers,infrared spectrometers, Fourier Transform near and far infraredspectrometers, ultraviolet and visible absorption spectrometers,fluorescence spectrometers, and X-Ray spectrometers. All otherspectroscopies which operate by observing the interactions and/orconsequences of the interactions between naturally-occurring,deliberately-induced, and/or accidentally-induced light and matter arealso of utility for this method.

For the spectrometer employing reflected, emitted or scatteredcharacteristic radiation, a Raman spectrometer, a near IR spectrometer,a IR spectrometer, a UV/Vis spectrometer or fluorimeter is suitable forcharacterizing the side surface of the borehole.

Previously, using spectrometers to measure dissolved methane in water orembedded methane at a remote location like a wellhead was not thoughtpossible. With the advent of portable and inexpensive yet highlyaccurate spectrometers, the measurement of dissolved methane in water ispossible. In some cases the spectrum used to analyze the material ofinterest may be obscured or blocked to some extent by the medium inwhich it is found. In the case of coal bed methane, the water andentrained particles may cause significant interference with anymeasurement of the dissolved or embedded methane. Certain steps may betaken to ensure a more accurate analysis of the methane.

Data correction, filters and steps to improve the signal of thespectrometer and methane may be used to accurately measure the methaneconcentrations. Methane has a characteristic peak or peaks in thescattered or returned optical spectrum. By adjusting filters and anydata correction equipment to the expected methane peak, the dissolvedmethane may be more accurately measured. Another way of correcting forthe interference of water or other entrained material is to adjust orselect the wavelength of the radiation used to decrease the effects ofthe water and entrained material and increase the returned signal due tothe methane. The wavelength may also be adjusted or selected toalleviate the effects of the length of the optical pathway. The lengthof the optical pathway from the spectrometer to the coal bed formationmay be 10,000 feet. The great length of pathway will result in increasederrors associated with the optical pathway. Means to adjust or correctthe laser radiation or returned radiation from the sample may beemployed at any location in the measurement system.

In an embodiment of this method, the spectrometers are physicallylocated outside of the water, while sampling probes are introduced intothe samples of interest. Such probes provide optical pathways via whichinteractions between light and matter are observed. In some cases, suchprobes also deliver the photons which interact with the matter. Theprobes used may have a lens to focus the source or characteristicradiation or filters to adjust the return spectrum radiation for anyflaws in the system or extraneous signals. The probes may need armoringor other means for protecting the probe due to the pressure and otherconditions of the well. The optical pathway or fiber optics may alsoneed protection from the conditions of the well.

When the probe is located extreme distances from the spectrometer, suchas down a well, corrections must be employed to correct for the inherenterrors due to the distance the source radiation and spectrum radiationmust travel. One way is to allow for longer periods of sampling in orderto receive several spectrums added together to analyze the methanepresent. Another way is to adjust the signal or radiation through afilter or correction device to allow correction feedback to adjust thereturn spectrum for flaws and errors associated with the radiationtraveling such distances.

In another embodiment of this method, the spectrometers are physicallyintroduced into the water so as to be near the samples of interest. Thismanifestation provides an unexpected benefit in that delivery of photonsto the samples and observation of interactions between light and matterare facilitated by the physical proximity of the spectrometers and thesamples.

Both embodiments may also use error correction devices such as darkcurrent subtractions of the return signal to correct for inherent systemnoise and errors. The systems may also use a technique of calibratingthe source radiation and spectrum signal to assure an accurate methaneconcentration measurement. Such techniques may include data processingfor comparing the signals to known spectrum signals. In order tocalculate the concentration of methane any of the known techniques ofcalculating the concentration from a spectrum may be used. A preferredmethod is partial least squares or PLS to calculate concentrations.

In order to realize a preferred embodiment of this method, it isnecessary to interface the spectrometers to the samples of interest.Interfacing the spectrometers and the samples can occur in several ways.Examples of those ways include, but are not limited to: direct opticalcoupling of the spectrometers and samples using light-guide devices;optical coupling of the spectrometers and chemicals which result fromphysically treating the samples; optically coupling of the spectrometersand chemicals which result from chemically treating the samples; andoptically coupling of the spectrometers and chemicals which result frombiologically treating the samples.

One manner of direct optical coupling of the spectrometers and samplesusing light-guide devices includes, but is not limited to, opticalcoupling of the interactions between light and matter via fiber opticdevices. This manifestation provides an unexpected benefit in thatdelivery of photons to the samples and observation of interactionsbetween light and matter occur with high throughput directly to thesamples in some cases.

A preferred manner of optical coupling is by way of direct transmissionof the radiation from the spectrometer to the sample via lenses, filtersand/or windows, and the direct transmission of the characteristicradiation from the sample to the detector by way of filters, windowsand/or lenses. Such direct transmission avoids injection of excitationand emission radiation into fibers and the associated signal powerlosses. Direct transmission reduces the effects of long distancetransmission through fiber optics and facilitates the close proximity ofa spectrometer and sample.

The filters used may be placed along the optical pathways of thespectrometer. The filters or dispersive elements, collectively filters,may be wavelength selectors, bandpass filters, notch filters, linearvariable filters, dispersive filters, gratings, prisms, transmissiongratings, echelle gratings, photoacoustic slits and apertures.

In order for the spectrometers to withstand the conditions particular towellbores, such as high pressure, low or high temperature, corrosiveliquids and dissolved solids, for example, it is preferable to enclosethe spectrometers in containers which protect them from such conditions.This novel method provides significant advantages over the prior art inthat the enclosed spectrometers can then be introduced directly into thewellbore. This method allows, but does not require, realization of thebenefit described by the direct interfacing or coupling of the samplesand spectrometers.

In order to interface the spectrometers and the samples using suchlight-guide devices in the wellbore, it is necessary to design theinterface in such a way that is suitable for the conditions particularto sampling environment, such as high pressure, low or high temperature,and dissolved solids, for example. The interface must withstand thoseand other conditions. One manifestation of such an interface for a fiberoptic probe includes, but is not limited to, a high pressurefeed-through jacket which interfaces between the conditions present inthe enclosed spectrometer and those present in the wellbore. Such ajacket provides significant advantages in that using such a jacketdirect optical coupling of the spectrometers to the samples becomespossible.

Methods of achieving optical coupling of the spectrometers and chemicalswhich result from physically treating samples includes, but is notlimited to, introduction of the samples into a portion of the enclosedspectrometers. That portion is then physically affected so thattreatment of the samples is achieved to give a chemical suitable for gasphase analysis via an optical pathway using one or more spectrometers.Such physical treatments include, but are not limited to,depressurization of the samples to release gas into a predefinedhead-space portion of the enclosure. That head space is then analyzedvia optical pathways using one or more of the spectrometers. This methodprovides an unexpected benefit in that gas-phase energy spectra ofchemicals are typically comprised of much higher resolutioncharacteristics than the corresponding liquid-phase spectra. Thus,delineation of complex mixtures of gases, such as methane and water, isfacilitated using this method.

The water located in the coal bed formation is considered to be stableor at equilibrium. The drilling of the well may agitate the water andmay cause clouding or fouling of the water. In some circumstances theeffects of the drilling and preparation of the well may be effect theconcentration of the methane in to artificially the water andsurrounding coal formations. Ways to correct the analyzed water may beemployed to more accurately reflect the true methane concentration ofthe formation at equilibrium. A simple way is to allow the well to comeback to an equilibrium after drilling or disturbance. Also, the probe orinstrument package that contacts the water in the coal bed formation maybe streamlined or controlled to allow for a smooth traverse in thewater. The locations of measurement in the well may also alleviate theeffects of destabilized water/methane concentrations. By analyzing thewater at the top of the formation first, and then continue withmeasurements down the well will effect the water equilibrium less whenmeasured before traversing the probe or package in the water to beanalyzed. A filter may also be used to strain the water or sample.

In order to accurately predict the capacity and the production of a coalbed methane formation by optical analysis, the well must be drilled toan appropriate depth. The depth of the water table, if present, thedepth of the top of the coal seam and the bottom of the coal seam arerecorded. The well head must be prepared to receive the probe orinstrument package. The probe must be coupled to the fiber-optic cable.The fiber-optic cable is coupled to the spectrometer that contains thelight source, dispersion element I detector and signal processingequipment and ancillary devices. The computer that serves as aninstrument controller I data collection and manipulation device isconnected to the spectrometer system. The system (computer1 spectrometerI detector and laser) are powered and the laser and operation equipmentare allowed to reach an operating temperature. The detector is thencooled to operating temperature. The probe or instrument package islowered into the well through the well reaches the water table. (headuntil the probe or package?) The source or laser emits a radiation andthe radiation is directed into the optical pathway or fiber-optic cable.The fiber-optic cable transmits the radiation down the well to theprobe. The probe emits the radiation onto the sample of interest. Theprobe may contain a lens or lenses to focus the radiation onto thesample at different distances from the probe. The radiation interactswith the sample and causes the sample to reflect, scatter or emit asignature or characteristic radiation or spectrum. The spectrum orcharacteristic radiation is transmitted through the probe and opticalpathway to the spectrometer. The spectrometer detects the spectrum orcharacteristic radiation and analyzes the spectrum for characteristicmethane peaks or peak. The spectrometer then outputs information to thedata processor to be manipulated into information to be used tocalculate the concentration and potential production of methane.

During the analysis an initial spectrum is taken at the depth of thewater table. The fluorescence is measured and, if the fluorescence ishigh, the source radiation wavelength may be adjusted or selected tomitigate the fluorescence. If particulates are present and the noiselevel from them is high, a different focal length may be chosen tomitigate the noise level. The integration time for the detectors ischosen to maximize the signal. A dark current spectrum is taken with theshutter closed such that no light reaches the detector. The dark currentis the noise that is present in the system mostly due to thermaleffects. This intensity is subtracted from each spectrum to lower thenoise level. The number of co-additions is chosen to balance signal andtime constraints. The co-additions will improve the signal to noise butwill increase the time for each measurement. The probe or package islowered to the top of the coal seam and a spectrum is taken. The probeis again lowered and a spectrum is taken at regular intervals of depthuntil the bottom of the well is reached. The measurements show aconcentration of methane in accordance with depth in the well. Bycorrelating the concentration of methane in the well with other data,the capacity of the coal bed formation or seam can be calculated. Theprobe is then refracted and the well head sealed.

This embodiment of the invention details the technical detailssurrounding the use of three different optical spectrometer systemscapable of identifying and quantitatively analyzing coal bed methaneformations. This embodiment centers around development of an instrumentpackage capable of detecting the chemical signatures of dissolvedmethane and other gases in water and detecting embedded or trappedmethane in subsurface coal seams, both from a lowered instrument packageand from a fixed monitoring site. Such optic-based instruments aresuitable for complex analysis of the physical and chemical properties ofdissolved methane and similar formations in the wellbore environments.

In these cases, the instruments themselves are packaged and adapted tothe conditions prevalent in these environments, and the formations areexamined in the natural state or after suitable treatment. This providesdirect access to the chemistry and geology of the formations to anextent unavailable from core-sampling techniques.

At least three types of spectrometers are suitable for wellbore remotesensing of methane. The first two spectrometers, UV/Vis and near IR, reparticularly suitable for head-space sensing of gases released afterdepressurization of the coal bed samples. UV/Vis spectroscopy providesdata relating to the molecular absorption properties of the water.Depending on experimental concerns, this data may contain informationregarding the identity and concentration of dissolved hydrocarbon gases.Regardless, though, it contains information related to choosing theproper laser excitation wavelength for the Raman spectrometer. Nearinfrared (NIR) spectroscopy has been widely used to remotelycharacterize complex gas mixtures. In this case, the NIR spectrometerprovides data related to the structure and bonding of the gas samples.If the spectrometer resolution is sufficient, that data containssufficient information to allow deconvolution of very complex samples.

Both of the above spectrometers require substantial fluid handling to beintegrated into the sensor or instrument package. This results in slowercollection times and, for the lowered instrument package, a lowerspatial resolution for the data, when compared to directly coupledin-situ methods. On the other hand, Raman spectroscopy is performedusing state of the art high-pressure probes, allowing rapid chemicalanalysis of water and methane with no additional hardware.

Raman spectroscopy detects the identity and concentration of dissolvedhydrocarbon gases and embedded hydrocarbon gases. The Raman scatteringof typical materials is quite low, producing significant signal-to-noiseproblems when using this type of spectroscopy. However, symmetricmolecules including methane show very strong scattering. This moderatessignal-to-noise concerns to some extent.

Again, all three spectrometers are refitted to suitable pressure tubespecifications. The tube-bound spectrometers will be immersed tosuitable depths on available well equipment or located adjacent thewell, and the data is collected using existing data translationprotocols. The data bandwidth for all three instruments is relativelylow ca (?). 50 KB per minute is a reasonable rate (dependent to someextent on the signal-to-noise concerns).

UV/Vis Spectrometer

Because UV/Vis spectrometers are based on low intensity, white lightsources, the use of focused optic probes (such as fiber optics) in thiscase is not appropriate. Such spectrometers are more suited to gasanalysis of the head space created after depressurization of a sample.Thus, in order to use the UV/Vis spectrometer for methane analysis,mechanized fluid controls are preferred.

An automated fluid decompression chamber that can be filled,depressurized, analyzed, and evacuated on a continual basis at the welldepth of interest is provided. Depressurization of the chamber releasesthe dissolved hydrocarbon gases into the resultant vacuum where they areefficiently and quickly analyzed by the UV/Vis spectrometer. Evacuationand flushing of the chamber is followed by another cycle.

Some issues of concern using this type of spectrometer are developingthe appropriate optical path for analysis, avoiding fouling of thechamber and optical windows by water-borne chemicals and bio-organisms,and establishing the appropriate temperature/pressure conditions fordata collection. Corresponding solutions are multiple reflectioncollection geometries which afford very high sensitivities, properintroduction of anti-foulants to the chamber during flushing, andlaboratory correlation of the entire range of availablepressure/temperature collection conditions to resulting data quality.

Doing such head-space analysis also provides a convenient method for thesensor platform to analyze chemically gas bubbles resulting fromdissolution, cavitation or mixing, which would not otherwise be suitablefor analysis. For example, diversion of captured gas into the head-spacethrough appropriate valves provides the opportunity for direct UV/Visand NIR analysis of the emitted gases.

Near IR Spectrometer

Near IR and Raman spectrometers detect the identity (i.e. molecularbonding) and concentration of dissolved and embedded hydrocarbon gases.Near IR analysis, widely used for quality control in industrialprocesses, typically gives moderate signals with sufficient information(i.e. overtones of the vibrational bands) to treat very complicatedsamples. Near IR spectrometers may be used for head-space analysis.Allowing multiple reflections of the beam through the cell (and thusmultiple passes of the beam through the sample) provides the unexpectedbenefit of increasing the signal-to-noise ratio of the data. Directoptical coupling of near IR spectrometers to the samples is alsopreferred.

Raman Spectrometer

Raman spectroscopy is widely used for in-situ analysis of water-bornesamples because water does not have a strong interaction with typicalRaman laser energies. The Raman spectrometer is based on traditionalgrating optics, and thus enjoys a high throughput of light.

Spectroscopic capabilities are maximized by, in some cases, using afiber-optic probe sampling motif based around a filtered, six-around-onefiber-optic probe. The six-around one fiber-optic probe allows for asafe, fully-sealed optical feed-through from the pressure vessel to thewater. This design removes the elaborate fluidics necessary for theother two spectrometers.

Until recently Raman spectroscopy would never have been considered as anin-situ probe due to the large size of available Raman systems and theirhigh power consumption. High efficiency diode lasers and charge-coupleddevice (CCD) detection, along with better filter technology have made itpossible to miniaturize Raman spectrometers and decrease powerconsumption. Fiber-optic probes have eliminated the complex samplingarrangements that once made Raman spectroscopy difficult and tedious.

A long output wavelength often provides useful spectra from samples thatproduce interfering fluorescence at lower wavelengths. Even at theselonger wavelengths, inorganic vibration shifts that are commonly 400 to1000 cm−1 wave numbers shifted in wavelength are still near the peaksensitivity of CCD detectors but with the added advantage of asignificant reduction in the background fluorescence interferencepresent in many samples. A preferred embodiment uses laser wavelengthswhich avoid to a reasonable extent any fluorescence characteristic ofthe sample.

Usually fluorescence is mitigated by providing a laser with a wavelengthabove the fluorescence. In a preferred embodiment a wavelength of 450 nmto 580 nm is provided from a diode laser. This range is below thewavelength of fluorescence of coal. The shorter wavelength is used todecrease the radiation from the coal and increase the relative radiationfrom the methane embedded or adsorbed on the coal.

Remote sampling is accomplished in some cases using a six-around-oneprobe. The epi-illumination probe incorporates one excitation and sixcollection fibers. This probe allows direct measurement of Raman ofdissolved hydrocarbons in water without having to transmit throughthick, non-quality optical window ports. High pressure feed-throughs areavailable for this probe.

Measurements of spectroscopic signatures of water-dissolved hydrocarbonsin the laboratory show an energy diagram of the known spectroscopicsignature regions of simple hydrocarbons, and the regions interrogatedby the three spectrometers considered herein. Thus, all threespectroscopies provide information relevant to the hydrocarbon identityand concentration.

However, the UV/Vis bands typical for these hydrocarbons are NOTstrongly characteristic. Many compounds absorb in the energy regionbetween 0 and 250 nm. Correlation of the UV/Vis results with those fromthe Raman and/or near IR leads to detailed chemical analysis. As well,the UV spectrometer must operate in the region where the methanetransition occurs.

The detectors used with the spectrometer system are important. To obtainhigh sensitivity and reduce interference from other substances a CCDtype detector is preferred. The charge-coupled device detector allowsfor only a small portion of the spectrum to be analyzed. Other detectorsinclude photomultiplier tubes, photo-diode arrays, CMOS image sensors,avalanche photo diodes and CIDs.

The measuring system may be supplied with power by the guide wires or byinternal batteries.

In order to predict or measure a potential production from a coal bedmethane field, a series of wells is measured. Taking measurements ofmethane or other substances of interest at a single well and at varyingdepths down the well provides a concentration of methane versus depthfor the well. This indicates the presence and amount of methane in thesubsurface zones or strata. By similarly measuring other wells in thecoal bed methane formation or field a dimensional plot of methane isobtained. From this the transport of methane, production zones andextent of methane bearing zones is obtained.

Determination of Coal Bed Natural Gas Production Factors and a System toDetermine Same

The following is a description pertaining to examples relating to coalbed methane wells, but it should not be seen as limiting the scope ofthe invention thereto.

As seen in FIG. 13, a typical completed coalbed natural gas wellincludes a borehole which is drilled to at least a depth of a coal seam.During drilling and completion of the well an initial borehole isdrilled to or through one or more coal seams and a casing is set to atleast the top of the lowest coal seam. Each coal seam of interest isthen accessed from the wellbore either by perforating holes from thewellbore into the coal seam, or by open hole completion of the wellboreat the lowest coal seam. In many cases the wellbore contains water whichoriginates from one or more layers of the geological strata, includingsome coal seams, through which the borehole is drilled, or that may beresidual from the drilling and completion process. In many instances thecoal seams of interest are wet which means that the coal contains waterin at least some portion of the coal seam. In some cases the coal seamscan be dry or partially dry which means that the coal seam has no orlimited amounts of water. In some cases, coal seams are stimulated orotherwise treated using techniques such as fracturing, acid treatment,recirculation of water, and other known methods.

Typically, production of methane is initiated by pumping fluid from thewell to reduce the pressure on the coal seam. This fluid typicallycontains dissolved methane, termed “solution gas”. When the overallhydrostatic pressure of the well at the depth of the coal seam islowered to the critical desorption pressure of the methane containedwithin the coal seam, further reductions in pressure lead to off-gassingof methane. At this point the well is considered to be in production.When a well is pre-production, the primary fluid flow through thereservoir is condensed phase, typically water. When a well is inproduction, both gas and condensed phase fluid flow through thereservoir, typically in competition. Gas flow is due to expansion of thegas after it devolves from the coal. Condensed phase fluid flow is dueto continued pumping of that fluid from the wellbore throughout most ofthe life of the well. In some cases, for wells that have beensubstantially dewatered and that have little or no hydrostatic pressureremaining, reduced pressure systems, e.g. vacuums, may be installed tofurther reduce the reservoir pressure and devolve and produce furthergas.

Depending upon the reservoir conditions and the coal type, formations,depth and other geological characteristics, fluid from a well may needto be pumped for a very short time (e.g. not at all, if over pressurizedwith gas) or for a very long time (e.g. up to four years or longer forseverely gas under saturated or low permeability coals) in order toreach production. The life of the well during which it produceseconomical amounts of methane, and the amount of gas that is producedduring that time, also varies depending on the amount of methaneentrained, contained, adsorbed or otherwise present in the coal bed. Incertain circumstances the life of a well may be up to 30 years orlonger.

As seen in FIG. 14 a known method of determining the critical pressurewhich the well must reach in order to produce methane by off-gassing isby determining an isotherm of the coal or coal gas content curve whichrepresents the amount of methane the coal may contain depending upon thepressure. A sample of the coal from the reservoir itself is subjected toreduced pressure over time to measure the amount of methane which itcontained. To this measurement is added a “lost gas” estimation toaccount for gas that issued from the coal sample during retrieval. Thetotal amount of methane is then plotted on the isotherm chart and acorrelation is made to the ideal curve. Where the saturation gas curveand measured gas content intersect is the critical pressure which mustbe reached by pumping in order for the well to produce methane. Otherfactors may be deduced from this plot or map.

In some cases, the partial pressure of methane may be reduced inwellbore fluids by intermingling with other fluids. In some cases theequilibrium between the methane adsorbed on the coal and the partialpressure of methane in the reservoir fluid may be affected byintroduction of another gas or other material that displaces the methanefrom the coal. This production enhancement method can affect therequired completion and production conditions.

As seen in FIG. 15 the methane present in the coal bed is interrelatedto the methane of the reservoir fluid which in turn is interrelated tothe methane present in the well fluid. As the pressure is reduced on thewell fluid, the pressure is in turn reduced on reservoir fluid and inturn reduced on the coal reservoir. Under some conditions, the coalreservoir, reservoir fluid and well fluid are initially at equilibrium.When one of these is changed the others are affected. The changes arenot instantaneous. For example, a reduction of the pressure in the wellfluid propagates from the well into the coal reservoir first affectingthe pressure of the reservoir fluid and then the pressure of the coalreservoir. The propagation of the change, whether it is pressure,concentration of a substance or the like, may depend on many factorsincluding the fluids, the coal reservoirs, permeability, porosity,density and cleating of the coal. However, given time the changepropagates as the system moves toward equilibrium by affecting the coalreservoir, reservoir fluid and well fluid properties.

When the methane present in the well fluid, reservoir fluid and coalreservoir are at equilibrium, these quantities are interrelated and ameasurement of one can be correlated into a measurement of all of them.As the fluid pressure is decreased in the wellbore fluid, the fluidpressure of the reservoir fluid is reduced and the pressure of the coalreservoir is reduced. In response to this pressure reduction, in mostinstances, the reservoir fluid simply flows into the wellbore andbecomes wellbore fluid as the two are hydrologically connected. As thesurrounding fluid pressure of the coal reservoir is reduced the coalreservoir seeks the new equilibrium and intra coal seam fluid flowoccurs. When the pressure of the coal reservoir reaches the criticaldesorption pressure, methane gas begins to flow from the coal itself.This process is what occurs when the well is dewatered by pumpingwellbore fluid. The water level or head is reduced so that the pressureis reduced and gas is produced.

During drilling the water or fluids are disturbed and mixed with otherstrata fluids. Given time the fluid or fluids come into equilibrium witheach other and the reservoirs of the well.

The wellbore and reservoir fluids, as seen in FIG. 15, have an effect oneach other as well as on the coal reservoir. A concentration of asubstance in the fluid, a pressure or other variable can locally changefor the well fluid. This in turn affects the reservoir fluid and thecoal reservoir. The change propagates into the reservoir fluid and coal,and the system responds by seeking to reestablish equilibrium. When acontinuous change is effected, such as when the well is continuouslydewatered, a flux or gradient develops between the well fluid and thereservoir fluid and coal. If the variables of the change, such aspermeability, rate of dewatering, rate of pressure change or othervariables, are known then the concentration, pressure or the like may becalculated for a given point within the reservoir fluid or coal. Thiscalculation may assist in determining the characteristics of thereservoir based upon a measurement of the well fluid when the well fluidis out of equilibrium with the reservoir. Thus, a measurement of the gascontent or critical pressure of the methane for the coal reservoir maybe calculated during dewatering, i.e. under non-equilibrium conditions.A computer model may be used to determine the flux or difference inconcentration or pressure as well as measurements of other variablessuch as the porosity, flow characteristics or other flux variablespresent in the well and reservoir.

In the case of methane in coalbed reservoir fluids, the partial pressureof methane is directly affected by the amount of methane contained orpresent in the coal bed reservoir and by the ease with which thatmethane can adsorb, absorb or otherwise be contained within the coal.For a given coal, the more methane that is present in the coalbedreservoir, then the higher the partial pressure of methane in thefluids. Thus, the partial pressure of methane in the reservoir fluid isdirectly related to the amount of methane in the coal reservoir. As thefluid pressure is reduced as with dewatering a well, reservoir fluid istransported from the coal reservoir to the wellbore. Once the partialpressure of methane at the depth of the coal seam equals the total fluidpressure, any further reduction in pressure causes the methane totransport off of or out of the coal reservoir as gas. An example of thisis when dewatering causes the overall reservoir pressure to be loweredbelow the critical desorption pressure in a coalbed natural gas well andgas production to commence.

Therefore, by determining a partial pressure of methane in the reservoirfluid the critical desorption pressure can be determined. As the partialpressure of methane is dependent on the amount of methane in the coalreservoir the partial pressure of methane does not significantly changefor a system at equilibrium. The partial pressure of methane in the coalreservoir fluid remains constant as long as the fluid pressure is abovethe critical desorption pressure. This constancy of the methane partialpressure in the coal reservoir fluid can be observed, for example duringa dewatering process when the hydrostatic pressure on the fluid is beingcontinuously reduced. Thus, the partial pressure of methane of thereservoir fluid is the critical desorption pressure for the coalbedreservoir.

As the partial pressure of methane of the reservoir fluid isinterrelated to the partial pressure of methane of the well fluid, bymeasuring the partial pressure of methane of the well fluid the criticaldesorption pressure can be determined. This, in turn, given an isothermof the coal, can establish the coal gas content of the coalbed reservoiras well as dewatering time, given the rate of pressure change, and canalso provide an estimation of the methane reserves within the coalreservoir. As shown in FIG. 16 the total reservoir pressure over timeduring dewatering may be plotted based on a linear or fitted curve andcompared against the methane partial pressure. The dewatering time maythen be determined.

Direct measurement of the partial pressure of the methane in the fluidor fluids can be made by a METS sensor or a total gas pressure sensorwith an appropriate filter. A measurement of a substance which isindicative of the methane partial pressure may also be used such ascarbon dioxide or nitrogen or other substances which chemically orphysically interact with the methane in the reservoir.

Another way of determining the partial pressure is by direct physicalobservation of the fluid in the well. In a wellbore, fluids near thebottom of the well can contain higher concentrations of methane andfluids near the top of the well can contain lower concentrations ofmethane. In other words, the saturation limit of methane in waterincreases with increasing pressure, which increases with increasingwater head or depth. For a wellbore fluid that contains dissolvedmethane, that methane will remain dissolved at depths where itsconcentration is lower than the saturation concentration and willcavitate as gas bubbles, to some extent, at depths where itsconcentration is higher than the saturation concentration. The depth atwhich cavitation commences is that depth at which the water headpressure is equal to the methane partial pressure. At depths above thispoint, the methane partial pressure exceeds the water head pressure andcavitation occurs. At depths below this point, the methane partialpressure is less than the water head pressure and cavitation does notoccur. By observing the depth at which cavitation occurs, it is possibleto calculate the partial pressure of methane in the wellbore fluid. Dueto the well water being saturated with methane at every depth above thatpoint, the well water will cavitate or form bubbles of methane at thosedepths. A video camera, acoustic device, bubble counter, thermocouple orother transducer of the like which is sensitive to the presence orevolution of bubbles in a fluid may be used to observe the depth atwhich the water head pressure is equal to the methane partial pressure.The pressure at this depth is then equal to the partial pressure ofmethane within the system or well fluid at the coal seam. This method ofdetermining the partial pressure has several drawbacks in that othergases could be cavitating which would affect the observation and otherdynamics of the well could offset the determination. In addition,supersaturation and nucleation effects in the fluid can introduce errorsinto the determination of the cavitation commencement depth. Anotherapproach to determining cavitation is to use an optical spectrometerthat can differentiate between the spectroscopic signature of methanedissolved in water and the gas phase methane in the bubbles. Thedifference in spectroscopic signature frequently manifests as a shift inthe absorption peak or Raman scattering peak for methane or other gasesindicative of methane, as well as changes in the width of such peaks.This method does not suffer from all of the drawbacks listed above, onlythe effects of supersaturation and nucleation, as well as dynamics ofthe well.

Another way of determining the partial pressure of methane within thesystem or well fluid is by capping the well and allowing the system toreach equilibrium. The capped well produces gaseous methane which fillsthe headspace of the well along with other gases. These other gases canbe water vapor, carbon dioxide or other reservoir gases. By measuringthe pressure of the head space the total pressure of the gases isobtained. Within this total pressure the partial pressure of the methaneis included. If the other reservoir gases are subtracted out, bymeasurement or by assumption, or assumed to be near zero, then theresultant pressure is the partial pressure of the methane As thispartial pressure of methane would be the partial pressure of methane inthe system the critical desorption pressure would be known. This methodis similar to a sipper tube or canister which draws in well fluid orreservoir fluid and is taken out of the well for analysis of the partialpressure of the methane in a similar manner.

In such cases a sample of the reservoir fluid under reservoir pressureand temperature conditions in a sealed vessel or in a tube or otherconveyance in which pressure is controlled—i.e. either maintained asconstant or varied in a known and reproducible manner—is collected. Thesample is allowed to come to equilibrium, or a relationship between thesample state and equilibrium is determined or estimated. The pressure ofthe vessel is measured, and the fraction of that pressure which is dueto the gas or gases of interest is measured or assumed. From thosequantities, the partial pressure of the gas or gases of interest iscalculated

Another example uses a sample collected and handled as above, in whichlocalized, microscopic or macroscopic changes in vessel pressure areinduced in order to induce gas evolution from the fluid. The system isallowed to come to equilibrium, or a relationship between the systemstate and equilibrium is determined. The pressure of the vessel ismeasured, and the fraction of that pressure which is due to the gas orgases of interest is measured or assumed. From those quantities, thepartial pressure of the gas or gases of interest is calculated. Thismethod has several drawbacks in that other gases including water vaporinterfere with the measurement and creates uncertainty. The assumptionsassociated herewith as well as the necessity of having equilibrium inthe well and fluid collection make this method undesirable.

Another example of determining the partial pressure directly is tosubmerge a vessel with a known volume, containing known or assumedfluids or gases and equipped with a gas-permeable membrane, intoreservoir fluid or a wellbore, and the dissolved gases in the water areallowed to equilibrate with fluid(s) and/or gase(s) in the headspace,then the gas partial pressure in the headspace is measured with apressure transducer or other transducer sensitive to the pressure,activity, fugacity or concentration of the gas or gases of interest.This can be combined with a sensor that identifies the fraction of theheadspace volume (and thus partial pressure) that is due to the gas orgases of interest.

The fluid within the well may also be physically altered. In one exampleof this method to determine the partial pressure one may stimulatecavitation in a reservoir fluid using a source of energy such as a sonicgun or the like and correlate the extent of cavitation as a function ofenergy to the partial pressure of the gas or gases of interest. Inanother example of this method, the reservoir fluid may be heated usinga variety of heating devices, including immersion heaters, microwavegenerators, or injection of steam of other hot fluids into a device,pipe or other container in contact with the fluid. The resultingincrease in temperature will reduce the solubility of the methane in thefluid. The correlation of cavitation to heat input and/or temperaturerise can be correlated to the partial pressure.

Of course another substance's concentration besides methane can also bemeasured to determine its partial pressure within the system. With thismethod the system should be at or near physical and chemical equilibriumin order to determine the partial pressure as it is at or in the coalbedreservoir.

Another example of a method of directly determining the partial pressureis to retrieve a volume of coal from the coal seam and seal the samplein a container at the reservoir conditions. This sample can then beallowed to off-gas methane in a sealed volume. When the sample comes toequilibrium the pressure in the sealed volume is the partial pressure ofmethane in the coal. This method is problematic in that retrieval of asample without affecting the methane partial pressure of that sample isdifficult.

Another determination of the partial pressure of methane in the fluid orfluids may be made by measuring the concentration of methane or othersubstance indicative thereof. As seen in FIG. 17 the following exampleis directed toward a method involving measuring a concentration of themethane in order to determine the partial pressure of the reservoirfluid and in turn to determine production factors, but should not beconsidered as limiting the method or apparatus.

A method of certain preferred embodiments of the invention involvesmeasuring a concentration of methane dissolved in a coalbed reservoirfluid, correlating that concentration to a partial pressure of methanein the fluid, correlating that partial pressure to the partial pressureof methane in the reservoir, and correlating that partial pressure ofmethane in the reservoir to a gas content in the coal as well asdetermining other production factors.

For example, FIG. 18 shows the Raman spectral signature of methanedissolved in water for three different samples having different methaneconcentrations.

By correlating the signals measured for a series of samples with theconcentrations of methane dissolved in the samples, it is possible tocreate a calibration between signal and concentration. FIG. 19 showssuch a calibration for Raman signal responses to methane dissolved inwater.

Dissolved methane concentration can then be calibrated to partialpressure of the methane in the reservoir fluid. For ideal fluids andconditions, this relationship is typically a simple linear relationship.For less than ideal fluids, or less than ideal conditions, thisrelationship may be complex. This relationship can be established forany fluid or condition by preparing samples of reservoir fluids underreservoir conditions, by impinging a partial pressure of methane ontothe sample until the system is at equilibrium and by then measuring theconcentration of methane. This process can be repeated for more than onepartial pressure of methane until a relationship between dissolvedmethane concentration and partial pressure is established. Typically,the partial pressures impinged would be of magnitudes that include thepartial pressure magnitude expected in the reservoir.

For example, a relationship between dissolved methane concentration andpartial pressure of methane typical of some coal seam reservoir fluidsand coal seam reservoir conditions is shown in FIG. 20.

The methane partial pressure in a reservoir fluid can thus be determinedby measurement of the dissolved methane concentration in that fluid.

The methane partial pressure in a reservoir fluid can then be used todetermine the methane partial pressure in an overall reservoir. Undertypical reservoir conditions, for fluids that are in physicochemicalequilibrium with the reservoir, the methane partial pressure in areservoir fluid or well fluid is equal to the methane partial pressurein the overall reservoir. For fluids that are not in physicochemicalequilibrium with the overall reservoir, one may correct the partialpressure to reflect that state.

The methane partial pressure in a reservoir can then be used todetermine the gas content of a coalbed reservoir. FIG. 21 shows such arelationship typical of coal.

Thus, measurement of the concentration of methane dissolved in a coalbedreservoir fluid can be used to analyze quantitatively the gas content ofthe coal.

Another way of performing certain preferred embodiments of the inventionare to measure the concentration of methane in the well at varyingdepths. This results in a plot of the concentration of methane versusthe depth as shown in FIG. 22. The concentration of methane is shownplotted with Henry's law (solid line), or other models of the saturationlimit of methane in water, against depth. As depth is increased, themeasured concentration is saturated to a certain point A. At this pointthe concentration of methane in the water deviates from the saturationcurve. This deviation point is indicative of the partial pressure ofmethane in the well fluid. The partial pressure of the methane in thewell fluid is the head or pressure of the water at the deviation point.As the concentration of methane in a well does not change below thedeviation point when the coalbed reservoir is not off-gassing, even onemethane concentration measurement below the deviation point candetermine the partial pressure of methane by correlation to Henry's lawor a saturation curve. With reference to the discussion above,cavitation would occur in such a well at any location in the well borefluid above Point A.

Other measurements made in a wellbore or on wellbore fluids or gases canbe combined with the methane concentration to provide a detailedunderstanding of the coal seam reservoir properties and stage ofproduction. This process can include measurement and/or analysis ofreservoir pressure, reservoir temperature, ionic strength of reservoirfluids, saturation limit of methane dissolved in water under reservoirconditions, depth and thickness of coal seams, coal rank, coalthickness, coal ash content, coal masceral content, wellbore diameter,wellbore total depth, casing size, casing type, cement type, cementvolume used, perforation locations, perforation sizes, perforation holedensity, historical water production volumes and rates, historical gasproduction volumes and rates, completion and production methodology,cone of depression, reservoir models, well structures, and otherrelevant variables.

Measurement of the dissolved methane concentration in a reservoir fluidcan occur using a number of different methods and apparatus.

Measurements can be made downhole in a well that is drilled into areservoir, and manipulated to contain the reservoir fluid. Suchmeasurements can be made using an optical spectrometer, such as a Ramanspectrometer. Such measurements can be made using a membrane-coatedsemiconductor sensor. Such measurements can be made using a massspectrometer. Such measurements can be made using a sensor such as anoptical spectrometer in tandem with a sample collector such as aformation tester or with a fluid control system such as a coiled tubingpump system. Such measurements can be made using a nuclear magneticresonance spectrometer or a radio frequency, acoustic frequency, ormicrowave frequency spectrometer. Such measurements can be made usingany transducer or sensor that provides a signal in response to methaneconcentration, including those transducers and sensors that may be lessthan quantitative in signal response.

Measurements can be made at the wellhead in a well that is drilled intoa reservoir, and manipulated to contain the reservoir fluid. Suchmeasurements can be made using standard laboratory analysis, e.g. viagas chromatography, on samples collected with various samplingapparatuses, including vessels that allow fluids of interest to flowinto them and then seal, on samples that are collected at the wellheadusing a pressure-regulated pumping system, and on other samplescollected using methods obvious to those skilled in the art.

In some cases, fluids in a wellbore are not representative of areservoir. For example, a wellbore drilled into more than one coal seammay contain commingled fluids that are representative of bothreservoirs, in some ratio. In these cases, concentration measurementscan likewise reflect the properties of both reservoirs, in some ratio.

Wellbores and wellbore fluids can be manipulated in order to ensure thatthe wellbore fluid properties, most specifically the methaneconcentration but also the temperature, pressure, ionic strength, and/orother physicochemical properties, reflect the reservoir properties ofinterest. For example, wells can be completed in only one coal seam sothat other coal seams or geologic intervals cannot contribute fluids tothe wellbore. In another example, the wellbore fluids in a well drilledinto a coal seam can be allowed to equilibrate with the coal seamreservoir until the wellbore fluids reflect the properties of the coalseam reservoir. In another example, the wellbore fluids can be extractedfrom the wellbore in order to induce fluid flow from the reservoir intothe wellbore until the wellbore fluids reflect the properties of thereservoir of interest. In another example, multiple coal seams in a wellcan be isolated using bridge plugs, packers, or other such apparatuses.The wellbore fluids in the isolated regions can then be allowed toequilibrate with the associated coal seam reservoirs, or one or moreisolated regions can be evacuated with pumps or other mechanisms inorder to induce fluid flow from the coal seam into the isolated regionsuntil the fluids in the isolated regions reflect the coal seam reservoirproperties of interest.

To manipulate wellbore fluids, the aforementioned formation tester, orother packer/pump assembly, can be used to extract fluid from thesidewall of a well until the fluid extracted represents the desiredreservoir property. In one case, this could involve using the formationtester to extract fluid from one coal seam, in a wellbore that containsfluids commingled from more than one coal seam, until the fluidcontained in the formation tester reflects only the properties of thatone coal seam reservoir. Then, the concentration measurement could beperformed on that sample either at the surface or in the well.

Fluid manipulations can be used to draw fluids from various places in areservoir, and thus provide the opportunity to analyze the properties ofthose places without drilling a well to them. For example, key reservoirvariables of a coal seam near a wellbore can be analyzed by measuringthe methane concentration and other properties of a wellbore fluid. Thewellbore fluid can then be removed from the wellbore so that additionalfluids flow from the coal seam into the wellbore. At some establishedtime, the wellbore fluids can again be analyzed with the expectationthat the fluids reflect the properties of the reservoir farther from thewellbore. In another example, a portion of the sidewall can be coveredso that fluid is removed from the surrounding coal reservoir in only onecardinal direction. Thus, the rate of fluid removal, and the propertiesof the fluid and substances that it contains, can indicate reservoirproperties of interest such as cleating orientation, fracturingorientation, and dewatering and production volume aspect ratio.

In one example of this technique, for a producing well that establishesa cone of depression near a wellbore, when the pump in that well isturned off the fluids from the surrounding coal reservoir flow into thewellbore. Near the wellbore, those fluids may be saturated in methanedue to depressurization of the wellbore. Farther from the wellbore,those fluids may not be saturated because the cone of depression doesnot reach their region. By analyzing the methane concentration as afunction of flow time, the cone of depression extent can be ascertained.This extent can be used to draw conclusions regarding whether the coalseam is being effectively depressurized and for how long the coal willproduce gas at that pressure. As shown in FIG. 23 the Henry's lawsaturation curve during pumping is represented (solid line) as well asthe saturation curve for when the pump is turned off (gray line). Bymeasuring concentrations of methane (solid circles) after the pump isturned off and plotting against the saturation curves, the relationbetween the curves and the concentrations show how effective the well isbeing produced as well as indicating the slope of the cone ofdepression, and thus dewatering time and permeability. Concentrations ofmethane near the pump off curve indicate that the well is being producedeffectively and that dewatering time has been long and/or permeabilityis high as well as a very small cone of depression. Concentrations closeto the saturation curve for when the pump is on indicate that the coneof depression may be large and dewatering time has been short and/orpermeability is low.

In some instances one coal seam can be extremely large. Some seams maybe 100 feet or larger in thickness. By measuring at different placesalong the coal seam the resultant partial pressures may be used toidentify and determine production factors that may not be representativeof one measurement. A cone of depression may actually be able to beidentified if the cone of depression has vertical stratification alongthe seam. Other variables for the seam may also be determined viameasuring along the entire width.

Measuring the methane concentration in a reservoir fluid, and analysisof other reservoir properties, thus allows analysis of criticaldesorption pressure, dewatering time and volumes, and other keyreservoir and operating variables.

For example, FIG. 24 represents a map of gas content and total reservoirpressure. The line indicates where in that space the coal gas content issaturated. Measurement of methane concentration, and thus gas content,for a coal at a certain reservoir pressure allows mapping of thatparticular reservoir onto this space. Reservoirs that adhere to thesaturation line contain coals saturated with gas. Reservoirs that do notadhere to the saturation line contain coals that are under saturatedwith gas.

Point A indicates an example reservoir that is under saturated with gas.In order for gas to be produced from that coal, the overall pressuremust be reduced until equal to the methane partial pressure, termed thecritical desorption pressure. Thus, measurement of dissolved methaneconcentration allows direct quantitative analysis of critical desorptionpressure.

Further analysis is possible using this type of map. FIG. 14 shows someexamples. By determining the pressure at the coal seam the saturation ofthe coal can be determined with reference to the isotherm. The gasrecovery factor may also be determined by determining the abandonmentpressure and correlating to the isotherm then calculating the recoveryfactor based upon the critical desorption pressure.

By measuring methane concentration in more than one wellbore, it ispossible to map more than one reservoir area (or more than one coalseam) onto a coal gas content versus pressure map as shown in FIG. 25.By doing so, it is possible to determine which coal seams will providethe most gas production in the least amount of time and/or with theleast amount of water production.

In some cases, the saturation line is the same or nearly the same formore than one area of coal or more than one coal seam, allowing directcomparisons to be made. In other cases, the saturation line must bemeasured, e.g. by adsorption isotherm analysis of cuttings, in order toallow comparison.

Conversion of a Raman spectrum of coal bed fluid to a gas content isbased on scientific principles. An exemplary conversion process issummarized below and shown in FIG. 26:

-   -   1) Raman measurement.        -   Raman, Temperature, Pressure, Conductivity.    -   2a) i) Conversion of Raman spectra to methane concentration.        -   ii) Conversion of methane concentration to partial pressure.    -   2b) Conversion of Raman spectra directly to partial pressure of        methane.    -   3) Convert methane partial pressure to coal gas content.

Working in reverse order, to calculate the gas content, the partialpressure of methane in the fluid surrounding the coal and the isothermof the coal are provided. The isotherm is a correlation, at a giventemperature, between the partial pressure of methane and the storagecapacity of the coal, i.e. saturated methane gas content. The isothermshould be known or estimated externally to the Raman measurement. Thus,the goal in making the Raman measurement is to determine the partialpressure of methane in the fluid surrounding the coal.

In order to make this conversion between a Raman spectrum and methanepartial pressure, the instrument is calibrated. This is done by one oftwo methods. Both involve preparing samples of methane in equilibriumwith water at various pressures. Raman spectra of the samples are taken.The pressures of the samples should correlate with the range of methanepartial pressures expected in the unknown samples.

The concentration of methane in each sample's fluid can be calculated byHenry's law, using an appropriate Henry's law constant for the givenconditions, i.e. temperature, salinity and methane partial pressure, orby some other method that indicates the solubility of methane in water.This methane in fluid concentration can then be correlated with theintensity of the methane peak in the Raman spectra of the sample. Thismethod is robust and has several advantages.

Alternately, the partial pressure of methane can also be directlycorrelated with the intensity of the methane peak in the Raman spectra.

With the above correlations, either methane concentration or partialpressure can be calculated by measuring the Raman spectrum of an unknownsample. Correlating directly to partial pressure, while simpler,introduces a larger possibility for error, as the unknown fluid may nothave the same relationship between dissolved methane and partialpressure, i.e. Henry's law constant (or other solubility relationship).Conversely, correlating to concentration and then to partial pressureprovides the advantage that the relationship between concentration andRaman signal will not be affected by differences in the fluid quality,without it being obvious in the Raman spectra, example: an unknown peakin the same spectral range as the methane. Subsequent conversion ofmethane concentration to partial pressure uses Henry's law and a Henry'slaw constant that is corrected for the unknown sample's temperature andsalinity, which can be measured in a wellbore, for example. In both ofthese methods the partial pressure of methane is calculated. This thenallows a direct reading from the isotherm (as shown in FIGS. 14 and 24)to determine the gas content.

Many factors such as localized depressurization may be taken intoaccount when determining the partial pressure.

Another example of the steps to determine the partial pressure basedupon an optical measurement of the methane concentration to reachpartial pressure is as follows. First, construct a calibration of Ramanor other spectrometer counts that relates those counts to methaneconcentration dissolved in water (preferably, an ideal water such asdeionized water). This requires that one first apply a methane partialpressure at a room temperature and allow the system to come toequilibrium; preferably this is done for a pressure range that exceedsthe range of interest in the well. Then, one measures the Raman signalfrom the methane in the ideal water sample and calculates the methaneconcentration dissolved in that sample. Then, one can correlate thisconcentration with the methane partial pressure that was applied, usinga Henry's law constant for water at room temperature. This gives acalibration between Raman signal, concentration in the water and partialpressure of methane above the water at room temperature.

Function ismoles of CH₄/moles of water=Pressure[atm]*Henry's constant[mM]CH₄=Pressure[atm]*Henry's constant*55 moles of water/literwater*1000

Second, record the Raman spectra of the unknown well sample, and itstemperature and salinity.

Third, from the Raman measurement and the calibration, a concentrationof the methane in the well water is calculated, via computer or model.

Fourth, with the methane concentration and a value of the Henry's lawconstant for the particular well temperature and salinity, calculate amethane equilibrium partial pressure. Values of Henry's law constant fortemperatures and salinities of interest are available in publishedliterature, or can be measured in the laboratory.

Fifth, obtain or generate a relationship between saturated coal gascontent at the reservoir temperature versus methane partial pressure,where the coal is in a saturated moisture state, i.e. at its equilibriummoisture content. This can be a general isotherm for the type of coal orfor more accuracy, the exact coal from the well.

Sixth, using the equilibrium methane partial pressure for the wellconditions (methane content, temperature and salinity), calculate a gascontent for the coal from the isotherm. With a valid isotherm for thecoal, the methane content of the coal can be read off the isotherm withthe partial pressure of methane. Another option is to use a Langmuir orother type of isotherm model equation to represent the true isotherm.The Langmuir and other model equations are equation versions of theisotherm. Using these one can calculate the gas content with theequation. Lastly, the accuracy of the values used for the Henry's lawconstant and the coal isotherm will have an effect on the accuracy ofthe calculations.

As described above, by measuring the partial pressure of methane oranother indicative substance or by correlating the concentration ofmethane to partial pressure a production value can be obtained. The useof an ideal gas content curve or coal isotherm is needed in order todetermine the coal gas content. As mentioned earlier a cutting or coresample of the coal may be used to determine the actual coal isotherm.However, an isotherm from a similar coal or coal type may be used aswell as an isotherm which is representative of a coal, coal type, coalformation or coal basin/region. In such an instance a library of coalsmay be compiled in order to allow automated determinations based on thecoal. This may result in a range of values dependent on the isothermsused. Another example of automating the determination of the coal gascontent is by using a model based upon equations.

Below is a method of determining the gas content from the partialpressure of methane via an isotherm model for a wide range of coals. Inthis model the actual coal isotherm for the coal being measured need notbe measured. However, to achieve a more accurate gas content an actualcutting or core and measurement of the coal can be done to determine theisotherm for the specific coal bed.

The correlation goes from P_(m) (methane partial pressure, which isobtained from the methane concentration and the appropriate value of theHenry's law constant) to G (coal gas content).

The Langmuir equation is:θ/(1−θ)=Ka;where θ is fractional gas coverage or gas content (i.e. θ=G/G_(sat) withG_(sat)=G at saturation, in scf/ton), K is the binding constant formethane to the coal and a is thermodynamic activity, which is related toconcentration and to “partial pressure of methane”, P_(m).

By analogy, a new Langmuir isotherm is defined:G _(sat){θ/1−θ}=K _(b) P _(m)where, K_(b) is the binding constant for methane to the coal in scf/tonpsi. This formulation has G approaching G_(sat) as P_(m) goes toinfinity. Now, using θ=G/G_(sat)G/{1−(G/G _(sat))}=K _(b) P _(m);G=K _(b) P _(m) −{GK _(b) P _(m) /G _(sat)};G{1+(K _(b) P _(m) /G _(sat))}=K _(b) P _(m)And finally,G=(K _(b) P _(m))/{1+(K _(b) P _(m) /G _(sat))}  Equation 1

With this comes G (coal gas content) from K_(b) and P_(m). Thelinearized reciprocal equation is:1/G=1/K _(b) P _(m)+1/G _(sat)  Equation 2

This linearized reciprocal equation was used to analyze the isothermshown in FIG. 27 below (i.e. plot 1/G versus 1/P, which gives 1/G_(sat)as the intercept and 1/K_(b) for the slope). This gives an R value of0.99953. It gives G_(sat)=178 scf/ton and K_(b)=0.175 scf/ton psi.

Using Equation 1 above with these values, one can enter any value ofP_(m) and obtain the corresponding value of G for coals for which thetypical isotherm in FIG. 27 is suitable. To predict the isotherm a bitmore closely reiterations and other modifications can be done.

Methods of directly determining or measuring amount of gas in a coalseam or region of a coal seam can include, but are not limited to,spectroscopies in which energy travels into the coal seam and interactswith methane or substances indicative of the amount of methane. Examplesinclude acoustic spectroscopy, microwave spectroscopy, ultrasonicspectroscopy, reflectometry, and the like. In an example case, microwaveradiation of the appropriate wavelength is impinged on a coal seam,travels through the coal seam to an extent that allows sufficientinteraction with methane, and a method of detection based on thatinteraction that provides the amount of methane entrained in the coalseam is used. That amount of methane is related to the gas content ofthe coal seam.

The apparatus to carry out certain preferred embodiments of theinvention includes as shown in FIG. 28 a partial pressure sensor ormeasuring device and a comparator for comparing the methane partialpressure to the isotherm. In one embodiment the partial pressuremeasuring device includes a concentration measuring device and acalibration system to calibrate the concentration of dissolved methaneto the partial pressure. The apparatus may include other sensors such asa temperature sensor, salinity sensor and/or a pressure sensor. Themeasurements for each of these may be used by the calibration system inorder to determine the methane partial pressure.

The system used to measure the concentration may also contain othermeasuring devices for salinity or electrical conductivity as well astemperature and pressure. Preferably, the system will measure thetemperature and the electrical conductivity of the reservoir fluid withthe concentration. This will allow a more accurate determination of themethane partial pressure in the reservoir fluid.

A system which includes a concentration sensor for use downhole may bepreferable due to its size and speed. An optical instrument for use downa well is comprised of a radiation source which is directed through aseries of optical components to a sampling interface where the radiationinteracts with a sample that is outside of the instrument and acrossthis interface. The returning radiation is then directed through aseries of optical components to a spectrometer. A controlling deviceinputs operating parameters for the spectrometer and packages spectraldata for delivery to an uphole computer. The entire instrument ispackaged in a steel housing, with additional sensors for pressure,temperature, and conductivity incorporated into the housing endcap. Theinstrument is attached to a cable head and lowered into a wellbore by awireline winch. The uphole computer and software allows a user to setoperating parameters for the instrument and graphically display datadelivered from the controlling device.

A calibration file is created by correlating response and spectra ofdissolved methane to known concentrations of dissolved methane. Thecalibration file is used to predict methane concentration from thespectra delivered uphole by the instrument. Several additionalcalibrations are created at various temperatures and salinities todevelop a library of Henry's law constants to be used in order tocalculate methane partial pressure. The values of temperature andconductivity measured downhole are used to choose an appropriate Henry'slaw constant from the library and calculate a methane equilibriumpartial pressure for the reservoir from the concentration measured bythe instrument. This methane equilibrium partial pressure is thecritical desorption pressure. As the total pressure (hydrostaticpressure) falls below the critical desorption pressure, the well beginsstable gas production.

Once critical desorption pressure is known for the reservoir, gascontent is calculated using the value for critical desorption pressurein conjunction with an isotherm that is representative of the coal'sability to sorb methane. An isotherm is a plot of total methane pressurewith respect to a coal's holding capacity for methane, in standard cubicfeet of gas per ton of coal. A technique as described above may be usedto determine an isotherm.

The rate at which the hydrostatic pressure head (water level) can belowered depends on the discharge rate of the pump, the well completionmethod, relative permeability of the reservoir and reservoir rechargerate. By noting the static water level before water discharge begins,one can monitor the hydrostatic pressure drop with a pressure transducerattached just above the pump and determine the rate at which thehydrostatic pressure drops with respect to total water discharge. Thisrate can be used to predict the time need to reach the criticaldesorption pressure of the well or the dewatering time as describedabove.

The depletion area of water from the reservoir, or cone of depression,can be modeled using hydrological assumptions and water discharge ratesto determine the lateral extent of reservoir at or below the criticaldesorption pressure and actively contributing to stable gas production.

As the exemplary descriptions have been used to explain the inventionwith regard to coalbed methane they should also be considered to includethe determination with regard to coal shale and other carbonaceousformations, and they should be considered to include the determinationwith regard to carbon dioxide, nitrogen, other hydrocarbons, and othergases, in addition to the methane as mentioned. The exemplarydescriptions with regard to measuring or determining concentration andthe production factors should also be considered to include otherprecursor variables and is not meant to be limiting.

The foregoing disclosure has been set forth merely to illustrate theinvention and is not intended to be limiting. Since modifications of thedisclosed embodiments incorporating the spirit and substance of theinvention may occur to persons skilled in the art, the invention shouldbe construed to include everything within the scope of the appendedclaims and equivalents thereof.

The methods disclosed herein may be used to analyze the fluid propertiesof individual coal seams in wells that have been drilled through morethan one coal seam. In the traditional use of straddle packers toisolate zones in multi-zone wellbores, measurements are only made onpressure changes and flow rates of fluid into or out of the zoneisolated by the packer assembly. Thus, it has not been possible toidentify the source of the fluid, nor has it been possible to determinethe fluid properties or composition for the fluid, causing uncertaintyas to the fluid properties representative of each of the multiplezones/coal seams. An unexpected benefit of the methods described hereinis that they allow measurement of fluid properties for fluids fromindividual coal seams in a well drilled through multiple seams, therebyenabling analysis of the total reservoir properties that arise from thecombination of properties of each of the coal seams in a given well.

Analysis of the fluid within coal seams is based on spectroscopicanalysis as described in U.S. Pat. Nos. 6,678,050 and 7,821,635. Thesepatents describe use of various forms of spectroscopic analysis tocharacterize the properties of a fluid in contact with or drawn from acoal seam. The cited method can be used, for example, to determine thepresence or concentration of dissolved gases in the fluid or otherproperties of interest. In one embodiment, the spectroscopic analysisuses Raman spectroscopy to determine the concentration of methane in thefluid. This allows assessment of the content of methane within a coalseam because the dissolved methane concentration in fluid that had beenin contact with the coal seam allows evaluation of the coal gas contentas a result of sorption equilibrium between the methane in the fluid andin the coal structure. An unexpected benefit of the present invention isthat it enables the assessment of the total coal gas content in wellswith multiple seams, which has heretofore not been possible without arange of assumptions and approximations related to the influence ofinterbedding (i.e. multiple coal seams) on the resulting gas-in-placeestimates (Mayor et al. SPE paper 35623, Improved Gas-In-PlaceDetermination for Coal Gas Reservoirs).

In one embodiment the invention is used to analyze fluid drawn fromindividual coal seams in a multi-seam well, which may or may not havealready been on production. In this case a test string, comprising astraddle packer assembly and at least one valve assembly, is loweredinto a well on a work string, comprising drill pipe or drill rods. It ispositioned in front of a coal seam, and the packers are used to isolatethat coal seam from the remainder of the wellbore, and especially fromother coal seams in the well. A valve above the straddle packer assemblyis opened to allow fluid to flow from the formation into the workstring. The rate of change of fluid pressure is measured in order toenable calculation of the permeability, skin damage, and other flowcharacteristics of the formation. Use of in-situ or surfacespectroscopic analysis of the fluid entering the test string revealswhether it is far acting formation fluid or invasion fluid. If it is faracting formation fluid, then the analysis further reveals keycharacteristics of the formation that has been isolated. If the fluid isinvasion fluid, in part or in total, then, a variety of methods,including but not limited to pumping, blow-downs, swabbing, can beemployed to move fluid from the coal seam into drill pipe or rods,referred to as the work string, above the straddle packer assembly.Monitoring of the fluid properties using either a down holespectroscopic analyzer or a set of optical fibers connected to aspectroscopic analyzer situated at the surface, or by bringing the fluidto surface under pressure exceeding the bubble point of the dissolvedgasses past a surface spectroscopic analyzer allows determination of theproperties of the fluid. This monitoring can be perpetuated until thefluid properties reach a steady state condition, where this conditionindicates that the fluid is representative of authentic reservoir fluidin the coal seam. Under such conditions measurement of the fluidproperties allows determination of selected properties of the coal seam,such as its methane content, as described above. Furthermore, when thecharacter of the fluid in the drill pipe or rods has been thus confirmedto be of far-acting reservoir character, one or more fluid samples canbe obtained and analyzed ex situ in order to reveal further propertiesof the reservoir. Once fluid of far-acting reservoir character isobtained, then it will be possible to obtain a direct measure of thebubble point of the dissolved methane by comparing the difference inpressure measurements obtained from pressure sensors situated atdifferent heights above the valve assembly. As representative fluidenters an initially empty work string from the coal seam, the differencein pressures measured by the two sensors will vary as a function of theamount of methane gas liberated from the fluid. This amount, and thusthe pressure difference, will gradually decrease as the height, and thushydrostatic head of the fluid column in the work string, increases.Eventually, the pressure difference will remain constant, with thebubble point of the dissolved methane equating to the hydrostatic headof the fluid column at the precise point in time when the difference inpressure measurements no longer varies, as illustrated in FIG. 33. Thisbubble point determination can also be equated to methane gas content ofthe coal. After these measurements, the packers may be unset, whichallows the test string to be moved to a second coal seam in thewellbore. The measurement and analysis described above may be repeated,allowing the determination of the properties of the second coal seam.This process may be repeated until substantially all of the coal seamsin a given well have been analyzed. This method allows the analysis ofkey production factors, e.g. the methane gas content, for each of theseams in a multi-seam well.

In another embodiment the invention is used to gauge the permeability ofindividual seams in a multi-seam well, preferably prior to extendedproduction (i.e. pumping) of the well. In this case, the test string islowered into a well and positioned in front of the target coal seam. Thepackers are then set to isolate that coal seam from the remainder of thewellbore. Then, a pump or other method may be used to move fluid intothe coal seam at pressures above the reservoir pressure. Following thisinjection, pumping is stopped, and the well is sealed. Monitoring of thepressure fall-off after pumping is stopped allows the calculation of thepermeability of the coal seam to fluid flow (as described in: Mayor etal. Analysis of Coal Gas Reservoir Interference and Cavity Well Tests,Society of Petroleum Engineers paper SPE 25860). Together with themethane content measurement techniques described above, this allows theassessment of the production capacity for methane for a particular seamin a multi-seam well because the production capacity results from acombination of the total methane content and the ability of the seam todeliver methane to the wellbore via its permeability. An unexpectedbenefit of this method is that it allows the assessment of the expectedcontribution of each coal seam to the overall methane production for awell with multiple coal seams, thus allowing the contribution of each ofthe individual coal seams to the overall methane production in a multizonal well to be predicted.

In another embodiment the invention is used to gauge the permeability ofindividual seams in a multi-seam well that has been produced for sometime (i.e. from which water or other fluid has been pumped or allowed toexit the well at the surface under its own pressure). In this case, thetest string is lowered into a well and positioned in front of the targetcoal seam. The packers are then set to isolate that coal seam from theremainder of the wellbore. Following inflow of fluids from the coal seaminto the test string a valve above the straddle packer assembly isclosed. Monitoring and analysis of the subsequent pressure build-up inthe wellbore between the straddle packers versus time allows a measureof the permeability of the coal seam using the radial flow analysis ofMuskat (Muskat, M.: The Flow of Homogeneous Fluids Through Porous Media,McGraw-Hill Book Co. Inc., (1937) 641) or related analyses (see, forexample, literature on Horner plots, as well as Mayor et al. Analysis ofCoal Gas Reservoir Interference and Cavity Well Tests, Society ofPetroleum Engineers paper SPE 25860, Mayor et al. Secondary Porosity andPermeability of Coal vs. Gas Composition and Pressure, SPE ReservoirEvaluation and Engineering, 2006, p. 114 (SPE 90255),Ehlig-Economides—Use of the pressure derivative for diagnosingpressure-transient behavior, Journal of Petroleum Technology, October1988, p. 1280). During this time, the use of spectroscopic analysisuniquely determines the origin of the fluid causing the pressurebuildup, thereby allowing identification of its source as being from thecoal seam that has been isolated with the packers. An unexpected benefitof this method is that it is possible to unambiguously determine thesource of the fluid causing the pressure buildup.

In another embodiment the invention is used to gauge the ability of agiven seam in a multizonal well to contribute to the overall methaneproduction from the well. In this case, the test string is lowered intoa well and positioned in front of the target coal seam. The packers arethen set to isolate that coal seam from the remainder of the wellbore.Then, an electrical submersible pump may be used to pump fluid out ofthe coal seam. Because the pump can be driven with a variable speedcontroller, it is possible to control the rate of fluid flow out of thecoal seam. In this embodiment the pumping rate is monotonicallyincreased while the properties of the fluid are monitored. At asufficiently high pumping rate, the fluid near the tool will begin tocavitate, forming bubbles. These bubbles may be produced either becausethe local pressure has fallen below the vapor pressure of water in thecoal seam fluid or from methane gas generation because the localpressure at the spectroscopic analyses sensing depth has fallen belowthe critical desorption pressure of methane desorption from the coal inthe coal seam/fluid system. In the former case, the bubbles will becomprised predominantly of water. This condition is caused because theflow rate out of the coal seam is insufficient to supply the flow ratedriven by the pump. In the latter case, the bubbles will be comprisedpredominantly of methane. In this case bubbles appear because the localpressure at the spectroscopic analyses sensing depth is below thecritical desorption pressure for methane from the coal seam.Spectroscopic analysis of the fluid containing the bubble allowsdifferentiation of these two cases, since the methane gas phase Ramanspectrum is substantially sharper and appears at a different wavelengththan that of methane dissolved in water. In this way it is possible todetermine whether the bubbles are comprised of methane gas or watervapor. This allows the determination of the maximum sustainable flow outof the coal seam (in the former case) or the critical desorptionpressure (in the latter case) both of which are desirable measurements.

In another embodiment the method and apparatus are used to compare fluidproperties for multiple zones in a multizonal well in order to determinewhether any of the zones or coal seams are connected (i.e. exhibit crossflow) away from the well bore. In this case, the test string is loweredinto a well and positioned in front of the target coal seam. The packersare then set to isolate that coal seam from the remainder of thewellbore. Then, an electrical submersible pump may be used to pump fluidout of the coal seam. The fluid properties, such as the methaneconcentration and carbon 13 isotope enrichment in the fluid, aremeasured as a function of time. This process is repeated for multiplezones in the well. Then, the time dependent data for each of the zonesare examined to look for cases in which the properties from a given zonechange gradually and converge on the properties of one or more otherzones in the well. Such convergence may be a signature of cross flowbetween zones at some location away from the wellbore. Unambiguousdetermination of cross flow is not possible using conventionaltechniques and comprises an unexpected benefit of the method hereindisclosed.

In another embodiment the invention is used determine the ¹³C/¹²Cisotopic ratio for methane in the fluid from individual seams in amulti-seam well. In this case, the test string is lowered into a welland positioned in front of the target coal seam. The packers are thenset to isolate that coal seam from the remainder of the wellbore. Fluidis drawn into the spectroscopic analyzer chamber. Spectroscopic analysisof the fluid is used to determine the amounts of ¹³C and ¹²C indissolved salts in the fluid by virtue of the differences in thevibrational frequencies for these molecules as a result is the differentmasses of the carbon isotopes. The ¹³C/¹²C isotopic ratio can be usefulin identifying the nature of the methane generation process in the seamas well as the origin of the methane. This ratio also may be used todistinguish methane from different sources, such as from different seamsin a formation comprising multiple seams. It is an unexpected benefitthat carbon isotope ratios for individual seams may be obtained and usedto analyze characteristics of the methane in the coal seams.

The methods described above are meant to convey the use of simultaneouszonal isolation, fluid flow wellbore pressure and spectroscopic analysisto characterize the fluid properties of fluids in coal seams or otherzones in multizonal wells, and to characterize the flow properties ofsaid fluids through said seams or zones (i.e. the permeability of saidzones or seams). This characterization is accomplished by management offluid flow in a manner in which such flow is isolated to an individualseam or zone combined with spectroscopic analysis of said fluid andmeasurement of fluid flow rates and fluid pressures. There are multipleways in which such measurements and analyses may be done. None of thedescriptions above are meant to be limiting with respect to the variouspossible permutations comprising such measurements and analyses.

Details of One Example Apparatus:

The Seam Isolation Test String (SITS) is a tubular assembly consistingof a conveyance means, referred to as the work string, typicallycomprising oilfield production tubing, drill pipe or drill rods, acontrol and monitoring umbilical, a power cable, shrouds which are anextension of the production tubing or drill pipe, electric submersiblepump (ESP), sensor assembly, packer(s), port valve(s), and inflationchamber. The tubular assembly is placed in a well at a depth where acoal seam of interest intersects the well. If the well casing extendsacross interval then perforations are placed in the well casing to allowcommunication of reservoir fluid with the well bore. In one embodimentthe sensor assembly contains a spectroscopic analyzer that analyzes thefluid properties. In another embodiment the sensor assembly contains oneor more optical fibers that bring light into and out of the sensorassembly, where this light is used to analyze the fluid properties.

FIG. 29 illustrates the Seam Isolation Test String assembly. Ascomponents are connected they are placed into the well bore insuccession. Connections of the control and monitoring umbilical andpower cable are made and the assembly is conveyed into the well casingon tubing or drill pipe. The umbilical and cable are fastened to thetubing at each connection interval by a clamping mechanism, FIG. 31, ormetal bands, typically every 30 feet.

The control and monitoring umbilical, FIG. 30, consists of multiplehydraulic conductors encapsulated in a protective polyurethaneextrusion. FIG. 30 illustrates a cross sectional view showing the jacketand 4 tubes containing hydraulic fluid and a tube containing fiber opticcable. The umbilical may also include optical fibers used to guide lightinto and out of the sensor assembly or an electrical conductor tofacilitate in-situ spectroscopic analyses. Each hydraulic conductorcontrols various components of the assembly. The present control andmonitoring umbilical incorporates four hydraulic conductors and a fifthelectrical conductor in the protective encapsulation.

The power cable is connected to the submersible pump, and to a variablefrequency drive at the surface. The variable drive allows for control ofthe pump speed and therefore the flow rate of the reservoir fluid beingdrawn from the coal seam of interest. This capability can be used tomatch the pumping flow rate to the natural flow rate, or recharge rate,of the coal seam where a constant flow without a subsequent drop inpressure is measured.

The submersible pump assembly is suspended in a shroud, an extension ofthe tubing or drill pipe, providing cooling for the pump motor. Thiscooling occurs as fluid is drawn from the reservoir through the tubing,around the motor, to the pump intake.

The sensor assembly is also suspended in a shroud. As fluid is drawn upthe tubing to the pump, the sensor actively measures fluid properties asit flows up to and around the assembly. In one embodiment the sensorassembly comprises a spectroscopic analyzer that analyzes the fluidproperties of the fluid in the sensor assembly chamber. In anotherembodiment, the sensor assembly comprises one or more optical fibersthat irradiate the fluid within the sensor assembly chamber and one ormore optical fibers that collect light scattered from or transmittedthrough the reservoir fluid. This collected light is carried to thesurface where a spectroscopic analyzer is used to analyze the fluidproperties. An unexpected benefit of the use of optical fibers is thatthey enable the use of down hole spectroscopic measurements when theconditions in the well do not allow the use of a spectroscopic analyzer,such as when the temperatures in the well near the coal seams exceed thetypical safe operating temperatures for the electronic devices in thespectroscopic analyzer or when the size of the wellbore is too narrow toallow insertion of a downhole spectroscopic analyzer.

The packers, or sealing mechanism, are inflatable elements energized bynitrogen pressure applied through the control line from the surface. Theuse of inflatable elements allows for the packers to be deployed in abroad range of well casing sizes and weights unlike mechanical packerswhich are limited in range for each particular size. Additionally, theinflatable elements do not require torque, tension, or compression to beenergized, allowing for the test tool string to be suspended in aneutral state within the well casing when positioning it for a test. Aninflation chamber containing fluid for energizing the packer elementsmay be included in the SITT test tool string to aid in creating a morepositive sealing action. When included, nitrogen applied at the surfaceacts upon a piston in the inflation chamber which transmits fluid to theinflatable elements. When nitrogen pressure is released the fluid in theelements is transmitted back into the chamber and stored until the nextinflation sequence.

Port valves have been included in the test tool assembly for multiplepurposes. When the assembly is being conveyed down into the well casing,both valves are in the open position. This allows for unobstructedequalization of the fluid column in the well bore annulus with thetubing. The valves are screened to filter out particulates. When a testbegins the upper port valve (A) is closed and fluid from the reservoiris drawn into the pump intake. In a case where fluid injection from thesurface is desired, or reverse circulating to wash around the SITT testtool assembly, both valves would be open providing a direct path aroundthe pump for the injected fluid. For a pressure fall off test followingfluid injection both valves would be closed and the pressure transientmonitored with a sensor located externally between the packers. Thisarrangement eliminates the “storage effect”, or compressibility, of thetubing fluid volume due to entrained gas, providing a much more accuratemeasurement than simply closing valves at the surface.

Alternative Configurations:

The SITT may be configured with a single sealing element for testing acoal seam that is under-reamed. This type of completion terminates thewell casing at the top of a coal seam and the well bore continuesthrough the seam. A sealing element is energized in the well casing justabove the open hole section through the coal seam and a reservoir fluidanalysis is performed.

Some reservoirs have artesian characteristics and a pump is not requiredfor moving reservoir fluid to the surface. Testing these types of coalseams only requires the sensor assembly, packers, and a port valve.

Although the inflatable element is the preferred method, the SITT may bedeployed with a mechanical sealing mechanism. These types of packerstypically require compression to energize the sealing elements. The SITTassembly can withstand a limited amount of compression and care must betaken when selecting this type of sealing mechanism.

State of the Art:

Sealing mechanisms for isolating hydrocarbon bearing zones are readilyavailable throughout the industry, commonly referred to as straddlepackers, and the like. A variety of packer types are available which canbe used to enable the invention, including retrievable mechanical setpackers, and pressure set inflatable packers. These mechanisms aredeployed with a variety of complementary tools such as valves, sensors,samplers, pumps, etc. The valves can be manipulated by using pressureapplied down the inside or outside of the deployment work string,rotation of the work string, changes in compression applied to the workstring, or vertical movement of the work string, with all types beingcompatible for use with the present invention.

FIG. 32 illustrates one embodiment to effect the disclosed inventionbased on use of an inflate-style test string with no external umbilicalsor power cables, and either a downhole spectroscopic analyzer, a surfacespectroscopic analyzer or a surface spectroscopic analyzer that iscoupled to a downhole sensor analysis chamber using optical fibers. Inthis case the test string is lowered into a well on a work string. It ispositioned in front of a coal seam, and the packers are used to isolatethat coal seam from the remainder of the wellbore, and especially fromother coal seams in the well. A valve situated at the bottom of the workstring is then opened to allow pressure communication with the coalseam. Then, a variety of methods, including but not limited toblow-downs, whereby the fluid level in the work string is depressed bypressure acting on the surface of the fluid, swabbing, can be employedto withdraw fluid from the coal seam into the work string. Properties ofthe produced fluid at the bottom of the work string can be determinedusing either a down hole spectroscopic analyzer deployed on a guide wirewith electrical conductors, or a guide wire with a set of optical fibersconnected to a spectroscopic analyzer situated at the surface. The guidewire is then pulled out of the work string. The pumping and subsequentspectroscopic analysis cycle is repeated until the fluid properties atthe bottom of the work string reach a steady state condition, where thiscondition indicates that the fluid is representative of authenticreservoir fluid in the coal seam.

Properties of the fluid at the bottom of the work string can also bedetermined by displacing the fluid in the work string to surface underpressure through a number of different flow paths, past a spectroscopicanalyzer situated at surface. Either a compressed gas, such as nitrogen,or a pressurized liquid, such as water, can be used as the displacementmedium, with the pressure applied to this medium being sufficient toprevent dissolved gasses being liberated from the produced fluid at thebottom of the work string. This pressure is regulated by means of avalve located in a choke manifold connected to the discharge flow linefrom the well. A window is included in the flow line upstream of thechoke to allow a spectrometer to analyse the fluid properties.

In one embodiment the produced fluid at the bottom of the work string isdisplaced up the work string, by injecting the displacement medium downthe annulus between the work string and casing. Alternatively, theproduced fluid at the bottom of the work string can be displaced up theannulus between the work string and the well casing, by injecting thedisplacement medium down the work string. In a second embodiment, aninner string is incorporated inside the work string, which could bedeployed separately from the work string, or be made part of the workstring. The produced fluid at the bottom of the string is displaced upthe inner string, by injecting the displacement medium down the annulusbetween the insert string and work string itself. Alternatively, theproduced fluid at the bottom of the work string can be displaced up theannulus created between the inner string and the work string itself, byinjecting the displacement medium down the inner string. The innerstring could comprise a separate single continuous length of tubing,such as micro coiled tubing, or comprise separate multiple joints ofthreaded tubing. Alternatively, dual wall drill pipe, known also asreverse circulating drill rods, could be used. These rods aretraditionally used with reverse circulating drilling systems, with theouter tube equating to the work string and the inner tube equating tothe inner string in the current invention.

Under such conditions measurement of the fluid properties allowsdetermination of selected properties of the coal seam, such as itsmethane content, as described above. After the measurement, the packersmay be released which allows the test string to be moved to a secondcoal seam in the wellbore. The measurement and analysis described abovemay be repeated, allowing the determination of the properties of thesecond coal seam. This process may be repeated until substantially allof the coal seams in a given well have been analyzed. This method allowsthe analysis of the methane content for each of the seams in amulti-seam well.

FIG. 32 further illustrates a belly spring 101 is run on the bottom ofthe tool string to provide drag and prevent rotation of the straddlepacker assemblies 103, 109 during the inflation & setting process. Areceiver sub 102 sits above the belly spring and below the bottomstraddle packer 103. This sub allows pressure in the sump 126 toequalize with annulus pressure 127 above the top straddle packer 109 viaan internal conduit 123 connected to bypass sub 110.

The Straddle Packer Assemblies 103 and 109 are comprised of a chassisand an interchangeable, inflatable, rubber element. These elements canvary in length. The Top Straddle Packer 103 contains an inner mandrel toaccommodate internal conduit 123 and conduit 124 used to set andmaintain pressure in the two Straddle Packers 103 & 109, while the otherStraddle Packer 109 also accommodates conduit 125, which provides a pathfor fluids between the test interval 128 and work string 122. Spacingpipe 104 and/or drill collars 105 are used to span the height of testinterval 128. Bypass pipe is run inside the spacing pipe 104 & drillcollars 105 to accommodate conduits 123 and 124. The outside recordercarrier 107 carries two electronic memory pressure gauges (EMPG orgauges) to record formation pressure and straddle packer inflationpressure. The flow sub 108 allows fluid exchange between the testinterval 128 and conduit 125. It also accommodates the other twoconduits.

Screen filter 111 filters out all coarse particles in the wellbore fluiddrawn into the inflate pump 112. It consists of an outer perforatedcase, a fine inner screen and two inner mandrels to accommodate allthree conduits 123-125. Both straddle packers are inflated by repeatedclockwise rotation, and deflated by compression and discrete clockwiserotation, of the inflate pump 112, which incorporates an interchangeablepressure relief valve dictating the maximum straddle packer inflationpressure. The inside recorder carrier (IRC) 113 includes two gauges torecord formation pressure. If pressure inside the conduit 125 increasesabove hydrostatic due to fluid squeeze generated during inflation of thepackers it is released into the annulus 127 through the squeeze reliefsub 114. If blow-down operations are used withdraw fluid from coal seaminto the work string 122 the squeeze relief sub 14 is not used.

The safety joint 115 features a course thread and a friction ringbetween the top and bottom sub. Should the test string become stuck itis possible to back-off the upper assemblies at the safety joint byrotating anti-clockwise. The back-off torque required is 60% of themake-up torque. The hydraulic jar 116 combines a hydraulic time delayand mechanical trigger mechanism that delivers a controlled jarringaction to help free stuck bottom hole assemblies. The hydraulic timedelay provides a temporary resistance that allows the drill pipe to bestretched. The trigger mechanism causes the tubing stretch to bereleased, with the resulting sudden contraction delivering a substantialimpact force.

Sample chamber 117 is mechanically connected to the hydraulic shut-intool (HSIT) or Valve Assembly 118, allowing it to capture a fluid samplewhen the Valve Assembly closes. The Valve Assembly is the downholetester valve that exposes the formation to the work string 122. It isoperated by vertical motion. The tool is open when compressed and closedwhen extended. There is a metering mechanism on the tool that preventsit from being inadvertently opened, with compression having to beapplied via the work string 122 for a certain time period before it willopen. There is no time delay mechanism associated with tool closure. Therecovery recorder carrier 119 contains a gauge that measures thehydrostatic pressure in the work string 122.

The impact reversing sub (IRS) 120 contains an internal brass pin thatcan be sheared by dropping a bar from surface down the work string 122.This then allows the higher pressure in the annulus 127 to enter thework string 122, allowing reverse circulation to occur. The pump outreversing sub (PORS) 121 is used as a backup to the IRS 120. In theevent that the IRS 120 does not function, pressure is applied down thework string 122, causing a brass pin in the PORS to shear, allowingpressure communication between the work string 122 and annulus 127. Workstring pressure is then bled off, with contents then reversed out bypump down the annulus 127. If blow-down operations are used to withdrawfluid from the test interval 128 into the work string 122 then the PORSis replaced with a multi cycle circulating valve (MCCV), which isindexed through several closed positions, a forward circulating positionand a reverse circulating position, by cycling of pressure down the workstring 122 between some threshold value above the pressure in theannulus 127 and another threshold value below the pressure in theannulus 127.

The foregoing disclosure has been set forth merely to illustrate theinvention and is not intended to be limiting. Since modifications of thedisclosed embodiments incorporating the spirit and substance of theinvention may occur to persons skilled in the art, the invention shouldbe construed to include everything within the scope of the appendedclaims and equivalents thereof.

The invention claimed is:
 1. A method of measuring and correctlyattributing fluid, geochemical and geomechanical properties toindividual coal seams in a well penetrating multiple seams, comprisingthe steps of: (a) deploying a test string, comprising a straddle packerassembly at least one valve assembly and two pressure gauges positionedat different heights above the valve assembly, into a well on a workstring; (b) positioning the straddle packer across a coal seam andsetting the packers to isolate that coal seam from the remainder of thewellbore and other coal seams in the well; (c) opening a valve above thestraddle packer assembly to allow fluid to flow from the coal seam intothe work string; (d) monitoring of fluid flow rates and pressures at thecoal seam during the flow period; (e) closing the valve above thestraddle packer assembly and monitoring pressure at the coal seam duringthe build-up period; (f) filling the test string with water to surface,move the valve above the straddle packer assembly to the circulationposition; (g) displacing the fluid in the work string under pressure tosurface; (h) diverting the fluid through a choke manifold at surfaceapplying sufficient back pressure to keep gasses dissolved in the fluid,while simultaneously monitoring fluid properties entering the chokemanifold; (i) pumping air or nitrogen down the work string to lower thewater level; (j) moving the valve above the straddle packer assemblyback to the closed position before any nitrogen enters the annulus; and(k) continue withdrawing fluid from the coal seam into the work stringabove the straddle packer until the monitored fluid properties,including dissolved methane content, reach a steady state condition,where this condition indicates that the fluid is representative ofauthentic reservoir fluid in the coal seam.
 2. A method according toclaim 1, wherein air or nitrogen is pumped down the work string todisplace the fluid in the work string under pressure to surface via theannulus between the work string and well casing.
 3. A method accordingto claim 1, wherein water or other liquid is pumped down the work stringto displace the fluid in the work string under pressure to surface viathe annulus between the work string and well casing.
 4. A methodaccording to claim 1, wherein air or nitrogen is pumped into the headspace in a separator vessel partially filled with water, which isdisplaced by the nitrogen pressure down the annulus between the workstring and well casing, thereby moving the fluid in the work stringunder pressure to surface up the work string.
 5. A method according toclaim 1, wherein water or other liquid is pumped down the annulusbetween the work string and well casing, thereby moving the fluid in thework string under pressure to surface up the work string.
 6. A methodaccording to claim 1, wherein air or nitrogen is pumped down an insertstring deployed inside the work string to displace the fluid in the workstring under pressure to surface via the annulus between the insertstring and work string.
 7. A method according to claim 1, wherein wateror other liquid is pumped down an inner string incorporated inside thework string to displace the fluid in the work string under pressure tosurface via the annulus between an insert string and work string.
 8. Amethod according to claim 1, wherein air or nitrogen is pumped down theannulus between the inner string and work string, thereby moving thefluid in the work string under pressure to surface up an insert string.9. A method according to claim 1, wherein water or other liquid ispumped down the annulus between the inner string and work string,thereby moving the fluid in the work string under pressure to surface upthe inner string.
 10. A method according to claim 1, wherein a downholepump is used to withdraw additional fluid from the coal seam.
 11. Amethod according to claim 1, wherein swabbing is used to withdrawadditional fluid from the coal seam.
 12. A method according to claim 1,wherein blow-down is used to withdraw additional fluid from the coalseam.
 13. A method according to claim 1, wherein monitoring of fluidproperties is achieved using a surface spectroscopic analyzer.
 14. Amethod according to claim 1, further comprising: obtaining concentrationof methane in the produced fluids and equating this to gas content inthe coal seam and thus total gas content for all seams penetrated by thewell and impact on gas-in-place estimates for the entire field.
 15. Amethod according to claim 1, where bubble point of the dissolved methanein the produced fluid is obtained from a plot of pressure differencerecorded by the two gauges on the vertical axis versus hydrostatic headof the produced fluid in the work string on horizontal axis, andequating this to gas content in the coal seam and thus total gas contentfor all seams penetrated by the well and impact on gas-in-placeestimates for the entire field.
 16. A method according to claim 1,further comprising: combining estimate of bulk permeability derived fromanalysis of the buildup pressure transient for each seam with estimatedgas content in each coal seam to determine production capacity of eachcoal seam.
 17. A method according to claim 1, wherein swabbing is usedto withdraw additional fluid from the coal seam, determining whetherbubbles formed due to cavitation are methane gas or water vapour basedon different Raman spectrum obtained for gaseous methane and methanedissolved in water, a downhole pump is used to withdraw additional fluidfrom the coal seam and further comprising maintaining pressure above thebubble point of dissolved gas within the sample.